Abstract: Systems and methods for detecting a gas kick within a wellbore are provided. The system includes a rotatable tool including one or more acceleration sensors and/or oscillators. The method includes rotating the rotatable tool in contact with fluid inside the wellbore and detecting changes in rotational velocity of the rotatable tool to detect the gas kick. In other aspects, the method includes detecting a change in density of the fluid within the wellbore by at least one or more pressure waves to determine the gas kick within the wellbore.

Abstract: Certain aspects and features relate to a system that selects an output value for controlling a drilling tool using dynamic force analysis coupled to fluid effects as part of a model that estimates projected torque and drag. A drilling model according to aspects and features of the present disclosure takes into account pipe axial elasticity as it relates to dynamic, time-based, force analysis and couples this relationship with drilling fluid effects over time. In some examples, a system calculates at least one dynamic sideforce and at least one dynamic, hydraulic force for each interval of time. An equilibrium solution for an output value using the dynamic sideforce and dynamic, hydraulic force for each time interval can be applied to the drilling tool for each time interval during drilling operations.

Abstract: A system can determine a temperature profile based on a prior production temperature profile and a reference start point pressure for a well. The system can virtually divide the well into a plurality of sections including uphill sections and downhill sections. The system can determine a gas-oil interface depth for each section of the plurality of sections from a water-oil ratio and a gas-oil ratio based on the temperature profile and the reference start point pressure. The system can determine an oil-water interface depth for each section of the plurality of sections from the gas-oil ratio and the water-oil ratio based on the temperature profile and the reference start point pressure.

Abstract: A system can assign a value to one or more sustainability factors for a wellbore operation based on historical data. The system can determine, for each of the one or more sustainability factors, a weight. The system can determine a sustainability index corresponding to a predicted carbon footprint for the wellbore operation based on the weight and the value for each of the one or more sustainability factors. The system can output a command for adjusting the wellbore operation based on the sustainability index.

Abstract: A method and system to drill a wellbore and identify drill bit failure by deconvoluting sensor data. The method comprises drilling the wellbore using a drill bit; and measuring data indicative of a parameter associated with the drill bit using a sensor located in the wellbore. The method also comprises decomposing the data to generate an intrinsic mode function of the drill bit data; and analyzing the intrinsic mode function to identify a drill bit failure. The system for drilling the wellbore comprises a drill bit; a sensor; and a processor. The sensor is located in the wellbore and operable to measure data indicative of a parameter associated with the drill bit. The processor is in communication with the sensor and operable to decompose the data to generate an intrinsic mode function of the drill bit data; and analyze the intrinsic mode function to identify a drill bit failure.

Abstract: Systems and methods for detecting a gas kick within a wellbore are provided. The system includes a rotatable tool including one or more acceleration sensors and/or oscillators. The method includes rotating the rotatable tool in contact with fluid inside the wellbore and detecting changes in rotational velocity of the rotatable tool to detect the gas kick. In other aspects, the method includes detecting a change in density of the fluid within the wellbore by at least one or more pressure waves to determine the gas kick within the wellbore.

Abstract: System and methods for optimizing coiled tubing string configurations for drilling a wellbore are provided. A length of a rotatable segment of a coiled tubing string having rotatable and non-rotatable segments is estimated based on the physical properties of the rotatable segment. A friction factor for the rotatable segment is calculated based on the estimated length. An effective axial force for one or more points of interest along the non-rotatable and rotatable string segments is calculated, based in part on the friction factor. Upon determining that the effective axial force for at least one point of interest exceeds a predetermined maximum force threshold, an effective distributive friction factor is estimated for at least a portion of the non-rotatable segment of the string. The rotatable and non-rotatable string segments are redefined for one or more sections of the wellbore along a planned trajectory, based on the effective distributive friction factor.

Abstract: A method includes comparing a natural frequency of a tubular with a frequency of each of at least two pulse generating devices positioned adjacent each other on the tubular, the tubular and the at least two pulse generating devices comprising an energy system; adjusting the frequency of at least one of the at least two pulse generating devices when the frequency is equal to the natural frequency of the tubular and obtaining an adjusted frequency different from the natural frequency; calculating an energy distribution in the energy system based on the natural frequency and the adjusted frequency of the at least one of the at least two pulse generating devices; and determining a new location on the tubular for positioning one or more of the at least two pulse generating devices such that energy introduced into the energy system is less than energy dissipated from the energy system.

Abstract: A method comprising determining a property of a first section of drill pipe that is to connect a first agitator to a second agitator in a bottom hole assembly of a drill string, determining a distance between the first agitator and the second agitator based, at least in part, on the property of the first section of drill pipe, positioning the first agitator in the bottom hole assembly of the drill string, and positioning the second agitator in the bottom hole assembly of the drill string relative to the first agitator based, at least in part, on the distance.

Abstract: Improved drilling systems and methods may include piezoelectric actuator(s) in a drill string at one or more locations to minimize or eliminate stick-slip while drilling. For example, piezoelectric actuators may be incorporated into the rock bit or drill bit in the openings in the bit body for receiving the cutters. As another example, the piezoelectric actuators may be incorporated into an independent module that is place on or in the drill string. The independent module may be placed between the top drive and the drill bit or at the top of the drill string near a top drive.

Abstract: The disclosed embodiments include a method, apparatus, and computer program product configured to performing automated downhole wellbore trajectory control for correcting between an actual wellbore trajectory path and a planned wellbore trajectory path. For example, in one embodiment, a PID controller is configured to obtain real-time data gathered during the drilling operation, determine whether the actual wellbore trajectory path deviates from the planned wellbore trajectory path, and automatically initiate the downhole wellbore trajectory control to change the actual wellbore trajectory path to a modified correction path that is determined using a minimum incremental wellbore energy method.

Abstract: Systems and methods for automated planning and/or control of a drilling operation are implemented to be based at least in part on automated prediction of well performance using an analytical well performance model. Substantially real-time determination of one or more drilling parameters and/or well trajectory parameters is based on measurements received from a drill tool together with the well performance model. The described techniques thus provide for automated, analytically determined well performance measures (e.g., well productivity and/or revenue) to a geosteering process. The well performance model accounts for variations of well trajectory both in inclination and in azimuth angle.

Abstract: System and methods for optimizing wellbore tubular design are provided. Design parameters for a wellbore tubular component are determined based on different types of axial loads expected during a downhole operation. The design parameters include load conditions at load points along the tubular component. An equivalent axial load is calculated for each load point, based on the corresponding load conditions. Design limits for the different types of axial loads are determined based on associated design parameters. A counter-load pressure is determined for at least one load point selected for each type of axial load, based on the corresponding equivalent axial load for each load point and a corresponding design limit for each type of axial load. At least one of the design limits is adjusted for the different types of axial loads, based on the counter-load pressure of the selected load point for each type of axial load.

Abstract: Systems and methods for detecting a gas kick within a wellbore are provided. The system includes a rotatable tool including one or more acceleration sensors and/or oscillators. The method includes rotating the rotatable tool in contact with fluid inside the wellbore and detecting changes in rotational velocity of the rotatable tool to detect the gas kick. In other aspects, the method includes detecting a change in density of the fluid within the wellbore by at least one or more pressure waves to determine the gas kick within the wellbore.

Abstract: A drill bit includes a bit body and one or more cutters positioned on the bit body at select locations. At least one vibrational device is positioned on the bit body to impart vibration to the bit body and thereby mitigate stick-slip.

Abstract: This disclosure is related to real-time calibration of drilling modeling programs and to the estimation of pipe stretch to perform corrections for the inclination and azimuth measurements and the estimation of pipe twist to perform corrections to the tool face setting. A measurement tool with a plurality of sensors is disposed along the drill string. Measurements are taken continuously during the drilling process from each of the sensors to determine torque, bending moment, and axial force data. This information is iteratively coupled with a mechanical torque-drag model (based on standard mechanics of deformable materials and on wellbore mechanics) to accurately estimate stretching and twisting of the drill string in real-time or near-real-time and thereby promote accurate wellbore placement.

Abstract: A method comprising determining a property of a first section of drill pipe that is to connect a first agitator to a second agitator in a bottom hole assembly of a drill string, determining a distance between the first agitator and the second agitator based, at least in part, on the property of the lirst section of drill pipe, positioning the first agitator in the bottom hole assembly of the drill string, and positioning the second agitator in the bottom hole assembly of the drill string relative to the lirst agitator based, at least in part, on the distance.

Abstract: Tubular elasticity is applied to determine tubular wear volume. In general, a torque and drag model is applied to calculate the dynamic stretch of the inner tubular string (e.g., drill string). The dynamic stretch is then integrated into a casing wear model to improve the accuracy of the calculated wear and its corresponding position along the outer tubular string (e.g., casing string).

Abstract: Tubular wear volume is determined using adjustable wear factors. The wear factors are applied as a function of the side force factor, friction factor, and/or temperature factor. The adjusted wear factors are then used to determine the tubular wear volume.

Abstract: In accordance with some embodiments of the present disclosure, methods and systems for modeling an advanced 3-dimensional bottomhole assembly are disclosed. The method may include determining a drill string property for a drill string having a rotary steerable drill bit; determining a drilling parameter for a drilling operation; generating a finite element model of the drill string based on the drill string property and the drilling parameter; performing a vibrational analysis of the finite element model; and predicting a drill string behavior during the drilling operation based on the vibrational analysis, the drill string behavior including a directional behavior, rate of penetration, or drilling efficiency of the rotary steerable drill bit.