A method of determining a parameter and state of a system from a time series of a system measurement, comprising using a processor to: a) build an approximate model of the system; b) sample a plurality of approximate system parameters for a current time interval from a posterior probability distribution; c) determine an estimate of the system parameter at the current time interval from the distribution of the plurality of approximate system parameters; d) determine an estimate of the system state at the current time interval given the estimate of the system parameter; e) repeat b) to d) for the next time interval. An apparatus for performing the method is disclosed, and application of the method to drilling and wellbores is discussed.

A drilling rig site may include at least one tubular configured to be inserted into a wellbore at the drilling rig, at least one imaging device configured to detect a location of an end of the at least one tubular or a feature of the at least one tubular, and a processor receiving an input from the at least one imaging device and configured to calculate a distance between the end of the at least one tubular and another element, a diameter of the at least one tubular, or movement of the at least one tubular. A method for completing a drilling operation at a rig site, may include capturing an image of a tubular at a rig site, the tubular configured to be inserted into a wellbore at the rig site, detecting a location of an end of the tubular or a feature of the tubular from the image, and determining a diameter of the tubular, a distance between the detected end of the tubular and another element, or movement of the tubular.

A method includes providing a Bottom Hole Assembly (BHA) in a wellbore. The BHA includes a rotary steerable system and a downhole attitude correction and control system. The downhole correction and control system includes a first sensor set, the sensors of the first sensor set positioned near ferromagnetic components of a drill string and a second sensor set, the sensors of the second sensor set positioned further from the ferromagnetic components of the drill string than the sensors of the first sensor set. Corrupted data from the first sensor set and reference data from the second sensor set is obtained, the corrupted data including cross-axis magnetometer and accelerometer measurements. The method additionally includes correcting the corrupted sensor data to form corrected sensor measurements and calculating an estimated azimuth from the corrected sensor measurements. The method further includes steering the rotary steerable system based on the estimated azimuth.

A method for calibrating a steering model may comprise estimating an initial condition for one or more variables in the steering model and calibrating the steering model with a Markov Chain Monte Carlo Simulation (MCMC). A drilling system may comprise a bottom hole assembly, a drill string connected to the bottom hole assembly, and an information handling system connected to the bottom hole assembly. The information handling system may be configured to process one or more measurements from the bottom hole assembly, calibrate a steering model based at least in part on the one or more measurements, adjust a control logic based at least in part on the steering model, and adjust the bottom hole assembly based at least in part on the control logic.

A drilling assembly includes a power section with a housing that rotates in a first direction at a drill string rotation rate. An output rotates a drill bit through a transmission shaft in the first direction at a rotor rotation rate relative to the housing. A bent housing between the power section and the drill bit rotates in a second direction at a variable rotation rate relative to the power housing. The transmission shaft extends through the bent housing. A mechanical brake system adjusts the bent housing's variable rotation rate. The bent housing rotates relative to the wellbore in a rotary mode, but not in a sliding mode. The sliding mode maintains the drill bit's direction and inclination while the drill string rotates. In all modes, the drill bit's rotation rate is the sum of the drill string rate and the rotor rate relative to the power housing.

Provided in some embodiments is a method of deploying a payload in a subterranean well. The method including advancing a torpedo in a first portion of a wellbore of a subterranean well (the torpedo including a body, a fiber-optic (FO) umbilical that is physically coupled to a surface component, and adapted to unspool from the torpedo as the torpedo advances in the wellbore, and an engine adapted to generate thrust to propel the torpedo), and activating the engine to generate thrust to propel advancement of the torpedo within a second portion of the wellbore such that the FO umbilical is disposed in the second portion of the wellbore.

A downhole drilling system for reducing impact of vibration comprises a drill string having a bottom hole assembly (BHA) and a controller configured to control the downhole drilling system. The BHA includes a measurement sub configured to measure one or more of lateral, torsional, and axial vibrations. In this system, the controller controls the downhole drilling system based on a drilling environmental profile including drilling parameters of one or more of the lateral, torsional, and axial vibrations and further based on a vibration mode and a vibration level of the one or more of the lateral, torsional, and axial vibrations determined from the drilling environmental profile.

A system for automatic detection of drill pipe coupling on a drilling machine is disclosed. The system may include a rotary head, a drill pipe, a display, and a controller. The controller may be configured to: automatically identify a coupling or decoupling condition of the drill pipe; monitor motion and forces associated with the rotary head during a coupling or decoupling action of the drill pipe; automatically identify a fully coupled or fully decoupled condition of the coupling or decoupling action based on the monitored motion and forces of the rotary head; terminate the coupling action based on the identification of the fully coupled or fully decoupled condition; and update the display to indicate the fully coupled or fully decoupled condition of the drill pipe.

Provided is a wellbore tractor and method for operating a well system. The wellbore tractor, in one aspect, includes a base member, and one or more turbines fixed to the base member for rotating the base member in a first rotational direction based upon a first direction of fluid flow. The wellbore tractor, according to this aspect, further includes one or more wellbore engaging devices radially extending from the base member, the one or more wellbore engaging devices contactable with a surface of a wellbore for displacing the base member and one or more turbines axially downhole as the one or more turbines rotate in the first rotational direction.

An underreamer for increasing a diameter of a wellbore. The underreamer may include a body having an axial bore extending at least partially therethrough. An electromagnetic activation system may be disposed at least partially within the bore of the body. A valve may be disposed within the bore of the body and coupled to the electromagnetic activation system. The valve may include a mobile element and a static element. The mobile element may be coupled to the electromagnetic activation system and move from a first position where the mobile element obstructs fluid flow through the valve to a second position where the mobile element permits fluid flow through the valve. A cutter block may be movably coupled to the body and move radially-outward as the mobile element moves from the first position to the second position.