Abstract: A system for monitoring the volume of cuttings exiting a shaker table is disclosed. The system comprises a shaker table configured to be adjusted based on information compiled by a processor and at least one camera configured to monitor said shaker table. The camera may be operably connected to the processor. The processor may be configured to identify drill cuttings and estimate the volume of the cuttings exiting the shaker table using machine vision techniques.

Abstract: A method for preparing a geothermal system involves preparing a wellbore that extends into an underground magma reservoir. Characteristics of the drilling process and the borehole are monitored to detect when the magma reservoir is reached, such that specially configured drilling operations can be performed to drill to a target depth within the magma reservoir.

Abstract: Systems and methods for using high rate telemetry to improve drilling operations. A method may include performing drilling operations with a wired drill pipe (WDP) string in an oil and/or gas well. The drilling operations may include pumping drilling fluid to a mud motor of the WDP string through an internal passage of the WDP string and vertically moving the WDP string via a drawworks while controlling the drawworks to change speed of the WDP string based on downhole data received by wellsite surface equipment via electrical conductors integral to WDP of the WDP string. The received downhole data may include downhole pressure data that is generated downhole by a pressure sensor and is indicative of pressure of the drilling fluid in the internal passage.

Abstract: Examples described herein provide a computer-implemented method that includes modeling at least one torque and drag parameter for an upstream well construction operation. The method further includes acquiring at least one measured torque and drag parameter during performing the upstream well construction operation. The method further includes interpolating friction factors at different sampling times for the at least one measured torque and drag parameter. The method further includes transposing the friction factors at the different sampling times for the at least one measured torque and drag parameter to a time-based series. The method further includes performing a corrective action responsive to determining that one or more of the friction factors at a particular point in time is indicative of the one or more of the friction factors deviating from an expected value.

Abstract: A downhole drilling apparatus, passing through a subterranean borehole, may mark an inner wall of the borehole with a marking element. A sensor, spaced axially from the marking element on the drilling apparatus, may subsequently sense the marking as it passes. A rate of penetration of the drilling apparatus may be calculated by dividing an axial distance, between the marking element and the sensor, by a time interval, between when the marking element marks the inner wall and when the marking is sensed by the sensor. Alternately, a second sensor, spaced axially from the first, may also sense the marking. A rate of penetration may then be calculated by dividing an axial distance, between the two sensors, by a time interval, between when the two sensors sense the marking.

Abstract: A drilling assembly control system is designed to control drill bit orientation such that a well path is followed that minimizes oscillations and deviations. When a deviation from the intended well path is detected, a predictive module models the deviated path. Using the modeled path, an optimization module utilizes a cost function and various constraints to analyze alternative correction paths in order to determine which correction path provides the most non-tortuous return to the intended well path.

Abstract: A recursive method of optimizing rate of penetration while drilling a well. The method can include collecting historical data on a plurality of drilling parameters, performing a mathematical analysis on the historical data to correlate each drilling parameter to a rate of penetration, determining an importance of each drilling parameter, establishing an operating envelope for each drilling parameter, and adjusting at least one drilling parameter to achieve a desired rate of penetration. The steps can then be repeated at a user defined interval.

Abstract: A lid for use with a downhole tool configured to house a beacon. The lid has an exterior and interior surface. A board is attached to the interior surface of the lid and electronic hardware is positioned between the board and the interior surface of the lid. The electronic hardware includes a pressure sensor. The pressure sensor is installed within the lid so that it is communicable with the exterior surface of the lid. When the downhole tool is positioned within an underground borehole, the pressure sensor measures the fluid pressure of any fluid surrounding the downhole tool. Measurements taken by the pressure sensor are transmitted to the beacon housed within the downhole tool. The beacon subsequently transmits such measurements to a tracker located at the ground surface.

Abstract: An electric drilling tool suitable for ocean under rater drilling rig is provided, which belongs to the technical field of ocean drilling equipment and includes a power supply assembly, a motor assembly and a bit assembly. The power supply assembly includes a power distribution cabinet, a power supply cable and a cable plug. The motor assembly includes a connecting joint, an upper machine head, a motor housing, a stator assembly, a rotor assembly, a centering bearing, stabilizing bearings, a rotating shaft, a lower machine head and a protector. The bit assembly includes a transition joint and a bit.

Abstract: This disclosure presents a process for communications in a borehole containing a fluid or drilling mud, where a conventional mud pulser can be utilized to transmit data to a transducer. The transducer, or a communicatively coupled computing system, can perform pre-processing steps to correct the received data using an average of a moving time window of the received data, and then normalize the corrected data. The corrected data can then be utilized as inputs into a machine learning mud pulse recognition network where the data can be classified and an ideal or clean pulse waveform can be overlaid the corrected data. The overlay and the corrected data can be fed into a conventional decoder or decoded by the disclosed process. The decoded data can then be communicated to another system and used as inputs, such as to a well site controller to enable adjustments to well site operation parameters.

Abstract: Systems and methods are provided for a fracturing process and in particular, to providing a fracturing system including a fracturing plug configured to seal a wellbore to prevent fluid from passing through the wellbore, a gun configured to generate a perforation cluster, wherein the perforation cluster allows fluid exchange between the wellbore and a subterranean formation, a setting tool configured to initiate setting of the fracturing plug and firing of the gun to generate the perforation cluster, and a sensor configured to measure parameters proximate to the wellbore, wherein the sensor is retrievable after a fracturing process, measuring the parameters proximate to the wellbore with the sensor and transmitting the parameters measured by the sensor to an operator.

Abstract: A system includes a drill string having a drill bit to drill a target wellbore, a processor, and a machine-readable medium. The machine-readable medium having program code executable by the processor to cause the processor to determine a mechanical specific energy (MSE) response during drilling of the target wellbore and determine a property of a formation around the target wellbore based on the MSE response.

Abstract: A system for improving drill bit performance, comprising processors and memory storing instructions to obtain a wear report for a drill bit, wherein the wear report includes wear characteristics of the drill bit and drill operating parameters under which the drill bit was used; compare the wear characteristics of the drill bit to a threshold for acceptable drill bit wear; and adjust drill operating parameters based on the wear characteristics of the drill bit. The instructions to obtain the wear report for the drill bit include instructions to analyze images of the drill bit to identify wear characteristics; identify wear patterns based on the wear characteristics of the drill bit; identify probable drilling conditions based on the wear patterns; and generate the wear report for the drill bit based on the images of the drill bit, the wear characteristics of the drill bit, and the probable drilling conditions.

Abstract: A method for formation property prediction may comprise drilling a borehole into a formation using a drill bit, measuring one or more parameters of drill bit motion, and inputting the one or more parameters of the drill bit motion into a formation property prediction model which outputs one or more properties of the formation. Another method may for forming a formation property model may comprise acquiring one or more formation properties and one or more parameters of drill bit motion, forming one or more data packets, and correlating the one or more data packets in the database to form the formation property prediction model that predicts a formation property based at least in part on drill bit measurements. A system may comprise a drill bit, gyroscope unit coupled to the drill bit in a known positional relationship, a magnetometer unit coupled to the drill bit, and an information handling system.

Abstract: A method for wellbore directional drilling includes selecting a starting and stopping spatial position of at least one portion of the wellbore. A sequence of sliding and rotary drilling operations within the portion is determined to calculate a wellbore trajectory. The sequence has at least one drilling operating parameter. The operations include a constraint on the drilling operating parameter or the calculated trajectory. The calculated trajectory includes a projected steering response of a steerable motor in response to the at least one drilling operating parameter. Drilling the portion of the wellbore is started. A spatial position of the wellbore during drilling is determined at least one point intermediate the starting and stopping positions. Using a relationship between the projected steering response and the drilling operating parameter, the drilling parameter and/or the constraint are adjusted based on the measured spatial position and the stopping spatial position.

Abstract: A system for drilling a borehole is disclosed. The system may include drill string having a bottom hole assembly a nuclear magnetic resonance tool within the bottom hole assembly, and a surface control system including a nuclear magnetic resonance measurement quality map. The control system may be configured to drill a borehole at a first set of drilling parameters and to receive motion properties from the nuclear magnetic resonance tool and adjust the drilling of the bore hole at a second set of drilling parameters. The surface control system may be further configured to adjust the drilling of the bore hole based on the motion properties from the nuclear magnetic resonance tool and the nuclear magnetic resonance measurement quality map.

Abstract: A three-dimensional hydraulic oscillator includes an upper casing, a lower casing screwed with the upper casing, an upper joint screwed with the upper casing, a lower joint screwed with the lower casing and a screw. An upper rotating shaft is mounted in the upper casing. A turbine group is mounted on the upper rotating shaft. An upper cam is fixed to the upper rotating shaft. A lower cam is movably mounted in the upper casing. The upper cam contacts with the lower cam. The screw is mounted in the upper casing and fixed to the lower cam. A lower rotating shaft is mounted in the lower casing. An eccentric block is fixed on the lower rotating shaft. A lower roulette is fixed to the lower rotating shaft. A shaft cap is disposed above the lower roulette. An upper roulette is mounted on the screw and meshed with the lower roulette.

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: A method, apparatus, and system according to which a drilling engine includes a template having a plurality of data fields outlining operational steps and parameters to perform a drilling process, the data fields having a plurality of recipe settings input therein to facilitate performance of the drilling process. A computer system communicates with the drilling engine and an operational equipment engine, and is configured to send a first control signal, based on the template and the recipe settings, to the operational equipment engine to cause the operational equipment engine to perform the drilling process to drill a first wellbore segment. A sensor engine is configured to monitor a key performance indicator (“KPI”) of the operational equipment engine during the performance of the drilling process. In some embodiments, the drilling engine includes a recipe optimization module configured to modify, based on the monitored KPI, at least one of the recipe settings.

Abstract: A method for automatically controlling drilling weight-on-bit for using a drill-string to drill along a wellbore includes establishing a drill-string model and a wellbore model, wherein the drill-string has a plurality of components along the length thereof, and the wellbore has a plurality of sections. A surface tension data of the drill-string can be acquired, and a friction coefficient-depth distribution can be obtained by calibrating the surface tension data in the drill-string model and wellbore model, and the drilling weight-on-bit can be predicted according to the calibrated drill-string and wellbore models.

Abstract: Systems, devices, and methods for visualizing and steering a drilling apparatus are provided, including a drill string with a bottom hole assembly (BHA), a sensor system, and a controller operable to generate a visualization comprising one or more drilling windows representing drilling tolerances of a drill plan of the drilling operation and a depiction of a location of the BHA based on the one or more measurable parameters of the drilled wellbore. The differences between the location of the BHA and the one or more drilling windows may also be visualized. This visualization may be used by an operator to steer the drilled wellbore.

Abstract: A method of operating a drilling system includes suspending a tubular drill string from a travelling assembly into an opening on a drill floor, operating a sensor to measure and to provide a first signal, providing a second signal, and comparing the first signal with the second signal. The travelling assembly is a part of a hoisting system. The first signal represents an acceleration or a velocity of the tubular drill string in a direction into or a direction out of the opening. The second signal represents an operational parameter of the hoisting system. The operational parameter is indicative of a vertical speed or of a vertical acceleration of the travelling assembly.

Abstract: Systems and methods for reducing or eliminating stick-slip are described. The system includes a controller and a drawworks. The controller is configured to collect downhole information, detect one or more stick-slip conditions, determine correlative relationships, model a stick-slip region, generate a control algorithm for top drive RPM and WOB that avoids a stick-slip region, determine a WOB autodriller set point for a particular top drive RPM using the control algorithm and provide one or more operational control signals that limit the WOB to the WOB autodriller set point for the particular top drive RPM. The drawworks is configured to receive the one or more operational control signals from the controller, and limit the WOB so that the WOB does not exceed the WOB autodriller set point for the particular top drive RPM.

Abstract: Predicting casing wear, riser wear, and friction factors in drilling operations may be achieved with data-driven models that use discrete inversion techniques to updated casing wear models, riser wear models, and/or friction factor models. For example, a method may applying a linear inversion technique or a nonlinear inversion technique to one or more parameters of at least one of a casing wear model, a riser wear model, or a friction factor model using historical data from a previously drilled well as input data to produce at least one of an updated casing wear model, an updated riser wear model, or an updated friction factor model, respectively; and implementing the at least one of the updated casing wear model, the updated riser wear model, or the updated friction factor model when designing and/or performing a drilling operation.

Abstract: Methods and systems are provided for optimizing a drill path from the surface to a target area below the surface. A method for operating an automated drilling program may comprise drilling to a target location along a drill path, updating a drilling path model based at least on data obtained during the state of drilling to the target location, creating a modified drill path to the target location based on at least the drilling path model in real-time as the step of drilling to the target location along the drill path is being performed, and drilling to the target location along the modified drill path.

Abstract: Methods, systems, and apparatus, including computer programs encoded on a computer storage medium for configuring a network edge device for communicating between an operational asset and a backend network that include the actions of establishing communication with a backend network through a first network connection. Establishing communication with a user computing device through a second, different network connection. Receiving an asset template that identifies communication protocols of the backend network and communication protocols of an operational asset to which the network edge device is coupled. Sending registration data to the backend network to register the network edge device and the operational asset with the backend network in response to receiving an instruction from the user computing device.

Abstract: A system and method for controlling drilling of a wellbore. The method may include supporting a tubular string using a top drive connected to a block, and lowering the top drive by lowering the block. The method may also include adjusting a position of the tubular string relative to the block using an actuator coupled with the top drive, the block, or both.

Abstract: Systems and methods for determining gravity toolface and inclination are described herein. An example may comprise a downhole tool (300) and a sensor assembly (330, 340, 350) disposed in a radially offset location within the downhole tool. The sensor assembly may comprise three accelerometers and an angular rate sensing device. A processor (402a) may be in communication with the sensor assembly and may be coupled to at least one memory device (402b). The memory device may contain a set of instruction that, when executed by the processor, cause the processor to receive an output from the sensor assembly; determine at least one of a centripetal acceleration (r) and a tangential acceleration (a) of the downhole tool based, at least in part, on the output; and determine at least one of a gravity toolface and inclination of the downhole tool using at least one of the centripetal acceleration and the tangential acceleration.

Abstract: Disclosed herein is a pressure compensation system for a bottom hole assembly. The disclosed pressure compensation system improves the responsiveness of a hydraulically actuated component carried by the bottom hole assembly.

Abstract: A method for transferring data between a surface computer and a downhole assembly may include connecting the surface computer to a single data port in the downhole assembly, transferring data between the surface computer and a first while drilling tool through the data port, and transferring data between the surface computer and a second while drilling tool through the data port.

Abstract: A system and method directed to passively compensating for the vertical movement of an offshore platform due to fluctuations of the sea level. The system, which is deployed from the offshore platform, includes an inline motion compensator, a top drive assembly and a static lift frame that are coupled together. In an embodiment, the inline motion compensator comprises an elongated vessel containing a piston which defines a blind chamber and a compensation chamber of the elongated vessel. The compensation chamber is filled with pressurized gas, which along with an elongated rod disposed therein, is used to compensate for the relative movement between the offshore platform and a hydrocarbon well assembly that it is coupled to system.

Abstract: Systems and methods for slide drilling are described. The system includes a controller and a drive system. The controller is configured to determine a resonant frequency of a drill string, generate a rotational acceleration profile having a frequency at least substantially similar to the determined resonant frequency, and provide one or more operational control signals to oscillate the drill string based on the generated rotational acceleration profile. The drive system is configured to receive the one or more operational control signals from the controller, and oscillate the drill string based on the generated rotational acceleration profile so that the drill string oscillates at a frequency substantially similar to the determined resonant frequency while slide drilling.

Abstract: According to aspects of the present disclosure, systems and methods for controlling the speed of a fluid-controlled drive mechanism are described herein. An example system may include a housing, a variable flow fluid pathway disposed within the housing, an electromagnet coupled to the housing, a fluid-controlled drive mechanism in fluid communication with the variable flow fluid pathway, and a load-generating assembly coupled to the fluid-controlled drive mechanism. An example method may include altering a variable flow fluid pathway disposed within a housing, wherein the variable flow fluid pathway is in fluid communication with a fluid-controlled drive mechanism, and generating an electrical current through an electromagnet, wherein the electromagnet is coupled to the housing.

Abstract: Directional control of a rotary steerable drilling assembly can be facilitated by a flow control module for maintaining a geostationary position or orientation of components of the assembly. The drilling assembly can include a bit shaft and an offset mandrel for adjusting a longitudinal axis of the bit shaft. A drive mechanism can rotate the offset mandrel independently of the bit shaft to maintain the offset mandrel in a geostationary position or orientation relative to a formation of the earth and/or a wellbore. A flow control module controllably directs a fluid flow to the drive mechanism. The flow control module can include an inner body and an outer body, defining an annulus there between and one or more blades within the annulus, each of the blades being rotatable to provide a range of angles with respect to a longitudinal axis of the flow control module.

Abstract: A drilling assembly includes a first tubular member supporting a first transmitter antenna and a steering assembly located beneath the first tubular member. The drilling assembly also includes an earth boring device comprising a drill bit. The drill bit has a body member, a bottommost surface and a gage surface at a stabilizing section of the drill bit. The earth boring device is supported beneath the steering assembly. The earth boring device includes a second transmitter/receiver antenna supported in spaced relation to the first transmitter antenna and within 36 inches of the bottommost surface of the drill bit, and at least one electrode generally at an outer surface of the stabilizing section of the drill bit.

Abstract: A method for determining position of a wellbore in the Earth's subsurface can include: actuating a seismic energy source at a selected location along the wellbore; detecting seismic energy with sensors located at known geodetic positions along the wellbore, the detected seismic energy being at least partially reflected by a casing of an adjacent wellbore; and determining the geodetic position of the wellbore at the selected location from the detected seismic energy.

Abstract: The present invention relates to a motion compensation system for an element hanging from a mobile unit, the system comprising two blocks, at least two articulated arms, a compensation cylinder and a cable. According to the invention, at least one characteristic length of the articulated system (for example: the length of a link or the distance between two sheaves of two articulated arms) is adjusted according to the motion to be compensated for.

Abstract: Exemplary embodiments of rotary pulsers are provided that include a stator and a rotor rotationally disposed adjacent to the stator. The rotary pulsers can include a regulator mechanism and a pump. Based on a parameter or condition associated with the rotary pulser, the regulator mechanism can adjust a parameter of the pump to control rotation of the rotor. Exemplary embodiments are also directed to methods of regulating a rotary pulser.

Abstract: Apparatuses, methods, and systems include rotary drilling a first segment of a wellbore by rotating a drill string with a top drive forming a part of a drilling rig apparatus for a first period of time; obtaining data from a sensor disposed about the drilling rig apparatus while rotary drilling for at least a part of the first period of time; and based on the data from the sensor, determining a proposed oscillation revolution amount for the drill string to reduce friction of the drill string in the downhole bore without changing the direction of a bottom hole assembly while slide drilling.

Abstract: An example method includes receiving a data set containing combinations of drilling parameter values and operating condition values for a drilling system corresponding to each combination of drilling parameter values. At least one of a frequency and a duration of use may be determined for each of the combinations of drilling parameter values in the data set. For at least some of the combinations of drilling parameter values, a contour map identifying the combinations of drilling parameter values, the operating condition values corresponding to the combinations of drilling parameter values, and at least one of the frequency and the duration of use may be displayed for at least some of the combinations of drilling parameter values.

Abstract: Casing wear estimation. At least some of the illustrative embodiments are methods including: calculating a value indicative of static casing wear of the drilling operation, the static casing wear caused by interaction of a drill string against an inside diameter of a casing; calculating a value indicative of impact casing wear of the drilling operation, the impact casing wear caused by interaction of the drill string against the inside diameter of a casing; and combining the value indicative of static casing wear and the value indicative of impact casing wear to determine the value indicative of aggregate casing wear.

Abstract: A method for managing a drilling operation includes generating, by a first sensor and a second sensor of a bottom hole assembly (BHA), a first time based data log and a second time based data log representing a borehole parameter along a drilling trajectory. A time shift is determined by comparing the first time based data log and the second time based data log. The time shift is processed along with an axial distance between the sensors to compute a rate of penetration.

Abstract: Calibrating Friction Factors. At least some of the illustrative embodiments are methods including: calibrating friction factor for a drilling operation by: plotting on a display device the expected hook load versus depth for the drilling operation; displaying plot points on the display device, each plot point indicative of a measured hook load versus depth for the drilling operation; selecting a plot point associated with a depth, the selecting responsive to a cursor hovering over the plot point on the display device; displaying a friction factor values which correlates the expected hook load versus depth for the particular depth to the measured hook load versus depth for the plot point, selecting the value responsive to the cursor hovering over the value; and then shifting on the display device at least a portion of the indication of expected hook load versus depth based on the value of friction factor.

Abstract: A method of automatically placing a drill bit used to form an opening in a subsurface formation on a bottom of the opening being formed comprises a) increasing a flow rate in a drill string to a target flow; b) controlling a flow rate of fluid into the drill string to be substantially the same as a flowrate of fluid out of the opening; c) allowing a fluid pressure to reach a relatively steady state; and d) automatically moving the drill bit toward the bottom of the opening at a selected rate of advance until an increase in measured differential pressure indicates that the drill bit is at the bottom of the opening.

Abstract: Rotary steerable drilling apparatus and methods utilizing apparatus comprising a shaft, a multi-angle strike ring axially repositionable along the shaft, an articulated member coupled to the shaft, and a steering member carried by the articulated member. An actuator is operable to maintain an angular offset of the articulated member relative to the shaft by maintaining azimuthally-dependent contact between the multi-angle strike ring and the steering member.

Abstract: A method of automatically placing a drill bit used to form an opening in a subsurface formation on a bottom of the opening being formed comprises a) increasing a flow rate in a drill string to a target flow; b) controlling a flow rate of fluid into the drill string to be substantially the same as a flowrate of fluid out of the opening; c) allowing a fluid pressure to reach a relatively steady state; and d) automatically moving the drill bit toward the bottom of the opening at a selected rate of advance until an increase in measured differential pressure indicates that the drill bit is at the bottom of the opening.

Abstract: Apparatuses, methods, and systems are described which assist in controlling toolface orientation of a bottom hole assembly. A controller instructs a top drive to oscillate a drill string an oscillation revolution amount to reduce friction of the drill string in a wellbore during a slide drilling procedure. A torque sensor detects torque at an interface between the drill string and the top drive, and the controller determines properties of a torsional wave from the detected torque that is propagating along the drill string during the slide drilling procedure. The controller determines a modification to the oscillation revolution amount and/or rotations per minute in order to control the toolface orientation in a desired manner. The top drive implements the determined modification and thereby assists in controlling the toolface orientation during the slide drilling procedure.

Abstract: A seismic data acquisition system is configured to collect seismic data. The system includes a marine source array configured to be attached to a fixed structure floating at the water surface and including vibratory source elements; and a controller configured to control the vibratory source elements so that a beam formed by the source array is steerable.

Abstract: A passive heave compensator comprising: a main hydraulic cylinder, including a moveable piston having a piston rod extendible through the main hydraulic cylinder and a piston head, a gas phase above the piston head, and at least one oil phase below the piston head separated by a boundary; an upper connection point associated with the main hydraulic cylinder and a lower connection point associated with the piston rod; and at least one accumulator, the or each accumulator having a moveable separator to divide the accumulator between a gas phase above the separator, and an oil phase below the separator, and the or each oil phase being in communication with an oil phase in the main hydraulic cylinder; characterized in that the main hydraulic cylinder further comprises a cylinder sleeve co-axial with the piston head to provide, in co-ordination with the piston head, the boundary between the gas phase and the at least one oil phase in the main hydraulic cylinder.

Abstract: An apparatus for forming a wellbore in a subterranean formation includes a drill bit, a connector connected to the drill bit and configured to transmit torque and thrust to the drill bit, and a drilling motor energized by a pressurized fluid. The drilling motor may include a stator and a rotor disposed in the stator and having a torque transmitting connection to the connector. The apparatus may also include a thrust generator associated with the rotor and having a pressure face in pressure communication with a fluid flowing through the drilling motor and a force application assembly selectively anchoring the stator to a wellbore wall. A related method uses the apparatus to drill a wellbore.