Abstract: A disclosed borehole curvature logging system includes: a drill string having a bottomhole assembly (BHA) with sensors providing actual deformation and bending moment measurements as a function of BHA position at spaced-apart intervals on the BHA; a processing system that retrieves said actual measurements and responsively generates a log of borehole curvature; and a user interface that displays the borehole curvature log. The processing system implements a method that generates the log by: providing an estimated borehole trajectory; deriving predicted deformation and bending moment measurements based on the estimated borehole trajectory; determining an error between the predicted measurements and the actual measurements; updating the estimated borehole trajectory to reduce the error; repeating said deriving, determining, and updating to refine the estimated borehole trajectory; and converting the estimated borehole trajectory into a borehole curvature log.

Abstract: An illustrative dogleg severity (DLS) estimation method includes: retrieving dimensions of steering assembly; determining an initial DLS estimate; using the DLS estimate in combination with the steering assembly dimensions to determine node displacements for a shaft portion of the steering assembly; deriving a bit side force from the node displacements while accounting for elastic bending in a housing portion of the steering assembly; performing a DLS calculation based in part on the bit side force; adjusting the DLS estimate if the DLS calculation does not match; repeating said using, deriving, performing, and adjusting until a match is achieved; and storing the DLS estimate on a nontransient information storage medium.

Abstract: Systems and methods for simulating the effects of syntactic foam on annular pressure buildup during annular fluid expansion in a wellbore to mitigate annular pressure buildup in the wellbore.

Abstract: Drilling system and methods may employ a weight-on-bit optimization for an existing drilling mode and, upon transitioning to a different drilling mode, determine an initial weight-on-bit within a range derived from: a sinusoidal buckling ratio, a helical buckling ratio, and the weight-on-bit value for the prior drilling mode. The sinusoidal buckling ratio is the ratio of a minimum weight-on-bit to induce sinusoidal buckling in a sliding mode to a minimum weight-on-bit to induce sinusoidal buckling in a rotating mode, and the helical buckling ratio is the ratio of a minimum weight-on-bit to induce helical buckling in the sliding mode to a minimum weight-on-bit to induce helical buckling in the rotating mode. The ratios are a function of the length of the drill string and hence vary with the position of the drill bit along the borehole.

Abstract: System and methods for simulating the effects of rupture disk failure on annular fluid expansion in sealed and open annuli to mitigate annular pressure buildup in a wellbore.

Abstract: In accordance with embodiments of the present disclosure, systems and methods for utilizing hybrid mechanical-laser drilling tools, such as drill bits and hole-openers, are provided. Such drilling tools may include mechanical cutters in addition to laser cutting mechanisms designed to focus laser beams toward a subterranean formation. The mechanical cutters and laser cutting mechanisms may work in combination to advance a wellbore through the subterranean formation. The drilling tools may be controlled to vary the amount of energy output through the mechanical drilling via the cutters and through the laser-assisted drilling via the lasers.

Abstract: In accordance with some embodiments of the present disclosure, methods and systems for modeling an advanced 3-dimensional bottom-hole 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.

Abstract: A casing wear estimation method includes obtaining a set of input parameters associated with extending a partially-cased borehole and applying the set of input parameters to a physics-driven model to obtain an estimated casing wear log. The method also includes employing a data-driven model to produce a predicted casing wear log based at least in part on the estimated casing wear log. The method also includes storing or displaying information based on the predicted casing wear log.

Abstract: Bottom-hole pressure operating envelops for underbalanced drilling take into account the lithologies of the formations being drilled through.

Abstract: A drilling system may include an outer sleeve, and a rotary steerable module including a shaft extending within the outer sleeve. The rotary steerable module may further include bearings disposed within the outer sleeve and through which the shaft extends, and cams positioned along the shaft between the bearings. Each cam may include an eccentric ring through which the shaft extends. Each extension of the shaft through one of the eccentric rings defines a bend in the shaft within the outer sleeve, the bend having a bend angle. A method of use and a drilling control apparatus are also provided.

Abstract: One drilling method embodiment includes: obtaining a set of drilling parameters, possibly from a drilling plan; applying the set of drilling parameters to a physics-based model to obtain an estimated log of a downhole parameter such as temperature; and refining the estimated log using a data-driven model with a set of exogenous parameters. Temperature cycling and cumulative fatigue (or other measures of failure probability or remaining tool life) may be derived to predict tool failures, identify root causes of poor drilling performance, and determine corrective actions.

Abstract: Estimating casing wear during a reciprocation portion of a drilling operation may take into account the forces that cause casing wear during the up and down strokes independently. For example, during a drilling operation, a method may include reciprocating the drill string through the wellbore for a plurality of up strokes and a plurality of down strokes according to reciprocation parameters; calculating an up stroke normal force and a down stroke normal force for the casing or a section thereof; calculating up and down stroke casing wears based on the up and down stroke normal forces, respectively, using a reciprocation casing wear model; calculating a reciprocation casing wear based on the up and down stroke casing wears; and calculating a total casing wear for the casing or the section thereof based on the reciprocation casing wear using a total casing wear model.

Abstract: Estimating casing wear for individual portions or lengths of a casing may take into account that individual drill string sections cause different amounts of casing wear based on the physical and material properties of each drill string section. In some instances, a method performed during a drilling operation may involve tracking a location of the plurality of drill string sections along the wellbore; corresponding a casing section with the drill string wear factors of the drill string sections radially proximate to the casing section the drilling intervals of the drilling operations; and calculating a drilling casing wear for the casing section based on the drill string wear factors corresponding to the casing section.

Abstract: The disclosed embodiments include a system, method, or computer-program product configured to performing automated wellbore trajectory control for correcting between an actual wellbore trajectory path and a planned wellbore trajectory path. For example, in one embodiment, a 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 wellbore trajectory control to change the actual wellbore trajectory path to a minimum-incremental wellbore energy correction path using provided correction constraints. The correction path may optionally include spline, catenary, circular arc, or clothoid curves.

Abstract: A directional tendency prediction system or method that provides: determining geometric parameters of a bottomhole assembly having at least a stabilizer, a bit, and an eccentering mechanism that provides a range of eccentricity settings; deriving a side force on the bit across the range of eccentricity settings; and based at least in part on the side force on the bit, determining a walk angle or dogleg severity (DLS) across the range of eccentricity settings. The resulting DLS range may be compared with requirements for a desired borehole trajectory and if suitable, the parameters may be used to configure the bottomhole assembly, and the DLS dependence may be expressed in a tabular or functional form to control steering.

Abstract: Disclosed embodiments include a method for estimating casing wear including the operations of: obtaining locations of survet points along a borehole, said survey point locations representing a borehole trajectory; casing at least a portion of the borehole with a casing string; deriving locations of adjusted survey points that represent a casing trajectory along said portion of the borehole, the casing trajectory being different from the borehole trajectory; estimating, as a function of position along said casing string, a side force of a drill string against the casing string; computing, as a function of position along the casing string, casing wear based at least in part on the side force; and generating a notification of any positions where casing wear exceeds a threshold.

Abstract: Disclosed are systems and methods of balancing weight and hydraulic energy distribution between downhole cutting tools. One system includes a drill bit arranged at a distal end of the bottom-hole assembly, a first sensor sub arranged proximate to the drill bit and configured to monitor weight-on-bit, a reamer axially-offset from the drill bit on the bottom-hole assembly, a second sensor sub arranged proximate to the reamer and configured to monitor weight-on-reamer, and a communications module communicably coupled to both the first and second sensor subs and configured to receive and process the weight-on-bit and the weight-on-reamer and adjust a hydraulic energy input to at least one of the drill bit and the reamer when a ratio between the weight-on-bit and the weight-on-reamer surpasses a predetermined operating threshold.

Abstract: A method of regulating downhole pressure using managed pressure drilling may include calculating an elasticity of a drill string during a drilling operation using a torque and drag model included in a managed pressure drilling (MPD) control system and calculating a surge pressure and a swab pressure acting on the drill string during the drilling operation using a hydraulics model included in the MPD control system. The surge and swab pressures may be based on movement of the drill string and in accordance with the elasticity of the drill string. The method may further include determining a set point pressure using a real-time hydraulics model and the torque and drag model, and operating a MPD choke system based on the set point pressure to regulate a predetermined downhole pressure at a predetermined location in a wellbore.

Abstract: A method including obtaining input attribute values and a target risk attribute value associated with a first borehole segment. The method also includes training a prediction model for the target risk attribute using the input attribute values and the target risk attribute value. The method also includes acquiring subsequent input attribute values. The method also includes using the trained prediction model and the subsequent input attribute values to predict a target risk attribute value for a second borehole segment. The method also includes storing or displaying information based on the predicted target risk attribute value.

Abstract: Disclosed are systems and method for automating downhole drilling based on the profile and energy of the wellbore being drilled. One method includes advancing a bottom hole assembly (BHA) within a subterranean formation and thereby forming a wellbore along an actual wellbore path, the BHA including a controller module, one or more sensors, and a steering assembly, taking survey measurements with the sensors at two or more survey stations along the actual wellbore path, comparing the survey measurements with data corresponding to a planned wellbore path, determining a return path based on minimum energy of the actual wellbore path when the actual wellbore path has deviated from the planned wellbore path, and conveying a corrective command signal to the steering assembly in order to reorient a trajectory of the actual wellbore path such that it returns to the planned wellbore path.