US Pat. No. 9,792,571

EFFICIENCY TRACKING SYSTEM FOR A DRILLING RIG

Nabors Drilling Technolog...

1. A drilling apparatus comprising:
a first sensor system connected to the drilling apparatus and configured to detect at least one measurable parameter of the
drilling apparatus;

a data input system operable to receive an efficiency target;
a controller in communication with the first sensor system and the data input system, the controller being operable to generate
an efficiency report for a drilling operation, the efficiency report including at least one Key Performance Indicator (KPI)
based on a measured time period taken to complete at least one measurable parameter of the drilling apparatus during the drilling
operation, the controller further operable to calculate an Invisible Lost Time (ILT) period based on a difference between
the at least one KPI and the efficiency target;

a drilling apparatus control device in communication with the controller and configured to control a drilling apparatus function
comprising moving at least a portion of the drilling apparatus, the drilling apparatus function forming at least a part of
the drilling operation based on the efficiency report; and

an output device in communication with the controller, the output device configured to output to a user the efficiency report
and the ILT period.

US Pat. No. 9,803,461

RIG FUEL MANAGEMENT SYSTEMS AND METHODS

NABORS DRILLING TECHNOLOG...

1. A system for managing power provided to a petroleum drilling rig, comprising:
a power source in electrical communication with the drilling rig, wherein the power source comprises a plurality of engine-generator
combinations (gensets); and

an engine management module that is operatively associated with the power source and that is configured to:
start an initial bank of gensets from the plurality of gensets;
monitor power consumption associated with the drilling rig;
recommend methods to manage power usage and generation associated with the drilling rig, wherein the methods comprise:
adding one or more gensets to the initial bank of gensets before an increase in power requirements is needed, and
distributing excess power to complete an activity earlier than specified in a drilling program; and
in response to the recommended methods, add the one or more gensets to the initial bank of gensets before the increase in
power requirements; and distribute the excess power to complete the activity earlier than specified in the drilling program.

US Pat. No. 9,328,602

MWD SYSTEM FOR UNCONVENTIONAL WELLS

Nabors Drilling Technolog...

1. A bottom hole assembly (BHA) for use with a downhole measurement-while-drilling (MWD) system for unconventional drilling
applications, the BHA comprising:
a drill bit having a cutting face; and
a sensor assembly comprising:
a sensor for measuring inclination, said sensor mounted at the lower end of the BHA adjacent to the drill bit;
an azimuthal gamma sensor, wherein the azimuthal gamma sensor is mounted within about 3 feet of the lower end of the BHA;
and

an annular pressure sensor mounted within about 4.5 feet of lower end of the BHA,
wherein the assembled sensor assembly is less than 40 ft in length.

US Pat. No. 10,041,308

OILFIELD TUBULAR CONNECTION SYSTEM AND METHOD

Nabors Drilling Technolog...

1. A mineral extraction system, comprisinga first oilfield tubular comprising a box connection having an axial shoulder;
a second oilfield tubular comprising a pin connection having an axial end face, the pin connection configured to threadingly engage with the first oilfield tubular within the box connection, and wherein the axial end face is configured to abut the axial shoulder when the pin connection is fully threaded within the box connection;
a first flange coupled to the first oilfield tubular;
a second flange coupled to the second oilfield tubular; and
a plurality of fasteners configured to couple to the first flange and the second flange.

US Pat. No. 9,810,056

ENVIRONMENT-BASED TELEMETRY SYSTEM

Nabors Drilling Technolog...

1. A telemetry system for use with a bottom hole assembly (BHA) of a downhole drilling system, comprising:
a processor configured to
activate the telemetry system to transmit drilling information upon a determination by the processor that the BHA has changed
from a horizontal position to a vertical position.

US Pat. No. 9,784,089

AUTOMATED DIRECTIONAL DRILLING APPARATUS AND METHODS

NABORS DRILLING TECHNOLOG...

1. A method of drilling to a target location which comprises:
receiving an input comprising a planned drilling path to a target location; an ideal mechanical specific energy (MSE); and
a predicted trend of a downhole parameter;

detecting real-time dynamic MSE parameters;
detecting a trend of the downhole parameter;
comparing the trend of the downhole parameter to the predicted trend of the downhole parameter;
determining a projected location of a bottom hole assembly of a drilling system, wherein determining a projected location
of a bottom hole assembly includes using a real-time survey projection as a directional trend;

calculating a real-time MSE based on the real-time dynamic MSE parameters;
comparing the projected location of the bottom hole assembly to the planned drilling path to determine a deviation amount;
comparing the real-time MSE to the ideal MSE;
creating a modified drilling path to the target location as selected based on the amount of deviation from the planned drilling
path, wherein creating a modified drilling path to the target location comprises:

creating a modified drilling path that intersects the planned drilling path responsive to the deviation amount exceeding a
first threshold amount of deviation and being less than a second threshold amount of deviation; and

creating a modified drilling path that does not intersect the planned drilling path responsive to the deviation amount exceeding
the second threshold amount of deviation;

automatically and electronically generating one or more drilling rig control signals at the surface of a well that steer the
bottom hole assembly of the drilling system to the target location along the modified drilling path;

creating a further modified drilling path to the target location when the trend of the downhole parameter is a reversal of
the predicted trend of the downhole parameter;

automatically electronically generating another one or more drilling rig control signals at the surface of the well that steer
the bottom hole assembly of the drilling system to the target location along the further modified drilling path; and

adjusting one or more drilling parameters responsive to the real-time MSE falling outside an ideal MSE range.

US Pat. No. 9,890,591

TOP DRIVE MODULE CONNECTOR AND METHODS

Nabors Drilling Technolog...

1. A top drive including a plurality of modules, comprising:
a first fastening member comprising a proximal end and a distal end, the proximal end extending from a first module;
a second fastening member extending from a second module;
wherein the first fastening member and the second fastening member are configured to be removably coupled to connect the first
module and the second module; and

a third fastening member comprising a proximal end and a distal end, the proximal end extending from a third module, wherein
the third fastening member is configured to be removably coupled to at least one of the first fastening member and the second
fastening member, to connect the first module, the second module, and the third module;

wherein the distal end of the first fastening member comprises a hollow portion formed therein, the hollow portion being configured
to receive at least a portion of the third fastening member to connect the first module, the second module, and the third
module.

US Pat. No. 9,784,035

DRILL PIPE OSCILLATION REGIME AND TORQUE CONTROLLER FOR SLIDE DRILLING

Nabors Drilling Technolog...

1. A method for controlling toolface orientation, comprising:
oscillating a drill string coupled to a top drive an oscillation revolution amount to reduce friction of the drill string
in a wellbore during a slide drilling procedure;

detecting a torsional wave traveling along the drill string produced in response to the oscillating the drill string during
the slide drilling procedure; and

modifying the oscillation revolution amount in response to the detected torsional wave to dampen at least a portion of the
detected torsional wave to maintain the toolface orientation of a bottom hole assembly on the drill string during the slide
drilling procedure.

US Pat. No. 10,233,740

STICK-SLIP MITIGATION ON DIRECT DRIVE TOP DRIVE SYSTEMS

Nabors Drilling Technolog...

8. A method, comprising:generating, by a controller, a torque command based on a difference between a detected rotations per minute (RPM) at a top drive coupled to a drill string of a drilling rig apparatus and a target RPM in a slow integration control loop;
generating, by the controller, a current adjustment command based on a difference between a detected amount of torque at the top drive and the torque command in a torque control loop; and
sending, from the controller, the current adjustment command to the top drive to accelerate or decelerate the top drive for stick-slip vibration mitigation.

US Pat. No. 9,919,903

MULTI-SPEED ELECTRIC MOTOR

NABORS DRILLING TECHNOLOG...

10. A method for controlling the torque of an AC motor, the method comprising:
providing the AC motor, the AC motor including:
a rotor, the rotor adapted to be rotated by the interaction between an internal induced reluctance or permanent magnetic field
and an electromagnetic field;

a stator, the stator including a plurality of windings, the windings adapted to induce an electromagnetic field to rotate
the rotor, the windings being grouped into winding phase groups, each winding phase group corresponding to and coupled to
a phase of AC power supplied to the AC motor, the winding phase groups selectively reconfigurable from a Wye configuration
to a delta configuration, and each winding phase group including at least two windings, the windings of each winding phase
group selectively reconfigurable between a series and a parallel configuration;

determining a first torque requirement;
configuring the AC motor into a first configuration in which the winding phase groups are configured in the Wye or delta configuration
and the windings of each winding phase group are configured in the series or parallel configuration, the first configuration
having a first torque ratio; and

supplying AC power to the AC motor, rotating the rotor.

US Pat. No. 9,898,916

ALARM SYSTEM

Nabors Drilling Technolog...

1. A system comprising:
a working environment; and
a control center separated from the working environment and configured to monitor systems in the working environment, the
control center comprising an odor alarm system configured to alert an operator at the control center by releasing at least
a first odor into the control center in response to an occurrence of an alert condition at the working environment,

wherein the alert condition comprises a critical condition or a dangerous condition.

US Pat. No. 9,869,126

VARIABLE DIAMETER STATOR AND ROTOR FOR PROGRESSING CAVITY MOTOR

NABORS DRILLING TECHNOLOG...

1. A mud motor for use in a wellbore, the mud motor comprising:
a rotor, the rotor including at least one helical rotor lobe extending therefrom;
a stator, the stator being tubular in shape and including at least two helical stator lobes extending inward from an inner
surface thereof, the at least two helical stator lobes interfacing with the at least one helical rotor lobe to create at least
one cavity between the stator and the rotor such that the cavity traverses the length of the stator as the rotor eccentrically
rotates within the stator;

wherein the distance between the stator and the rotor at an interface between the at least two helical stator lobes and the
at least one helical rotor lobe at a given point along the mud motor defines a tolerance; and

wherein the rotor and the stator are formed such that the tolerance at a first point along the mud motor is wider than the
tolerance at a second point along the mud motor, wherein the first point along the mud motor is positioned nearer the upper
end of the mud motor than the second point along the mud motor.

US Pat. No. 9,903,168

TUBULAR HANDLING METHODS

First Subsea Limited, La...

1. A method of handling a tubular in a casing or drilling operation, comprising:
operating a running tool to interact with and grip a tubular section comprising at least one tubular;
applying a rotational force to the tubular section, at least one surface of which is engaged with and gripped by a portion
of the running tool, to at least partially disconnect the tubular section from a tubular string;

operating a tubular member elevator to interact with and grip the tubular section or a portion thereof; and
raising the tubular section relative to the running tool to separate the tubular section from the tubular string and to disengage
the engaged and gripped at least one surface of the tubular section from the portion of the running tool.

US Pat. No. 9,995,840

AZIMUTHAL MINOR AVERAGING IN A WELLBORE

Nabors Drilling Technolog...

8. A drilling rig apparatus, comprising:a bottom hole assembly comprising:
a sensor configured to detect measurement data from a borehole while the bottom hole assembly is in the borehole; and
a bottom hole assembly transceiver configured to transmit a first subset of the measurement data associated with a first hemisphere of a radial plot; and
a surface control system comprising:
a surface transceiver configured to receive the first subset of the measurement data associated with the first hemisphere; and
a surface controller configured to mirror the first subset of the measurement data associated with the first hemisphere to represent a second subset of the measurement data associated with a second hemisphere of the radial plot, and to generate an image log using the first subset of the measurement data and the represented second subset of the measurement data.

US Pat. No. 9,932,802

DOWNHOLE SLOT CUTTER

Nabors Drilling Technolog...

12. A method, comprising:positioning a slot cutter into a first position relative to a tubular positioned within a wellbore;
displacing a mandrel into a housing of the slot cutter in a first direction along a central axis of the housing;
directing a die radially outward from the housing of the slot cutter and into the tubular via displacement of the mandrel;
engaging a cutting portion of the die with the tubular, wherein the cutting portion comprises a smooth, semi-circular outer radial surface and a substantially constant width, and wherein the substantially constant width is generally perpendicular to the central axis of the housing;
puncturing the tubular with the cutting portion to form a slice of the tubular; and
displacing the mandrel in the housing in a second direction opposite the first direction along a central axis of the housing such that the die retracts radially inward toward the housing.

US Pat. No. 9,926,719

SLINGSHOT SIDE SADDLE SUBSTRUCTURE

Nabors Drilling Technolog...

19. A land-based drilling rig comprising:a first and second lower box, the lower boxes positioned generally parallel and spaced apart from each other;
a drill floor coupled to the first lower box by a first strut, the first lower box and first strut defining a first substructure, the drill floor coupled to the second lower box by a second strut, the second lower box and second strut defining a second substructure, the struts hingedly coupled to the drill floor and hingedly coupled to the corresponding lower box such that the drill floor may pivot between an upright and a lowered position, the drill floor including a V-door, the V-door oriented perpendicularly to a long axis of one of the substructures;
a first and second raising hydraulic cylinder, the first and second raising hydraulic cylinders connected to the drill floor and the lower box; and
a mast, the mast mechanically coupled to one or more of the first substructure, the second substructure, and the drill floor, the mast being pivotably coupled to one or more of the first substructure, the second substructure, and the drill floor by a pivot point.

US Pat. No. 9,915,097

BEARING SECTION OF A DOWNHOLE DRILLING MOTOR

Nabors Drilling Technolog...

13. A downhole drilling motor, comprising:
a housing;
a drive shaft disposed in the housing and rotatable with respect to the housing about an axis;
a transmission;
a drive shaft cap coupled between a first axial end of the drive shaft and the transmission, wherein the drive shaft cap is
coupled to the drive shaft via a threaded connection;

a bearing section disposed between the housing and the drive shaft to facilitate rotation of the drive shaft relative to the
housing;

a lock nut threaded onto the drive shaft adjacent the bearing section; and
a machinable spacer positioned against the drive shaft cap and the drive shaft, wherein the machinable spacer and the lock
nut define a double shoulder connection, and wherein the drive shaft cap is torqued to apply a pre-determined compressive
force to the bearing section.

US Pat. No. 10,094,137

SLINGSHOT SIDE SADDLE SUBSTRUCTURE

NABORS DRILLING TECHNOLOG...

1. A method comprising:transporting a land-based drilling rig to a well field and positioning the land-based drilling rig, wherein the land-based drilling rig comprises:
a first substructure;
a second substructure, the second substructure being positioned generally parallel to the first substructure;
a drill rig floor coupled to the first and second substructures, the drill rig floor including a V-door, the side of the drill rig floor having the V-door defining a V-door side of the drill rig floor, the first and second substructures pivotably supporting the drill rig floor; and
a mast, the mast mechanically coupled to one or more of the first substructure, the second substructure, and the drill rig floor, the mast being pivotably coupled to one or more of the first substructure, the second substructure, and the drill rig floor by a pivot point, the mast comprising a V-door side, the V-door side of the mast parallel to the first or second sub structure;
positioning the mast in a horizontal position; and
raising the mast from a horizontal to a vertical position.

US Pat. No. 10,003,229

LOW INERTIA DIRECT DRIVE DRAWWORKS

NABORS DRILLING TECHNOLOG...

1. A low inertia permanent magnet motor comprising:a shaft;
a stator, the stator including a plurality of windings, the windings positioned to induce a rotating electromagnetic field into the interior of the stator; and
a rotor, the rotor positioned within the stator, the rotor including a generally cylindrical, hollow rotor body and a plurality of permanent magnets, the permanent magnets coupled to the periphery of the rotor body, the rotor body coupled to the shaft only by one or more extensions extending between the rotor body and the shaft, the extensions coupled directly to the rotor body and the shaft, the rotor positioned to be rotated by the interaction of the rotating electromagnetic field induced by the stator and a permanent magnetic field of the permanent magnets.

US Pat. No. 10,094,209

DRILL PIPE OSCILLATION REGIME FOR SLIDE DRILLING

Nabors Drilling Technolog...

1. A drilling method, comprising: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 to obtain historical information taken over the at least a part of the first period of time;
based on the obtained historical information from the sensor, determining a proposed oscillation revolution amount for the drill string to reduce friction of the drill string in the wellbore without changing a direction of drilling of a bottom hole assembly on the drill string; and
slide drilling a second segment of the wellbore while oscillating the drill string using the proposed oscillation revolution amount during a second period of time.

US Pat. No. 10,185,050

COMPENSATED TRANSMIT ANTENNA FOR MWD RESISTIVITY TOOLS

NABORS DRILLING TECHNOLOG...

1. A transmission assembly for a resistivity tool in a wellbore comprising:an electronics package comprising an RF transmitter, the RF transmitter adapted to transmit an electromagnetic signal through a transmission antenna, the electronics package having a first antenna output and a second antenna output;
the transmission antenna formed from at least one transmission winding, the transmission antenna having a first end coupled to the first antenna output and a second end coupled to the second antenna output; and
a compensation coil formed from at least one compensation winding, the compensation winding wound parallel with the transmission winding, the compensation coil having a first compensation end connected to the second transmission antenna output and a second compensation end not connected to any electronic device or ground, wherein a voltage induced in the compensation coil by the transmission antenna is of opposite polarity to a voltage of the transmission antenna.

US Pat. No. 10,094,176

SIDE SADDLE SUBSTRUCTURE

NABORS DRILLING TECHNOLOG...

23. A substructure for use in a land-based, box-on-box drilling rig, the substructure comprising:a substructure frame, the substructure frame configured to at least partially support a drill rig floor, the drill rig floor fixedly coupled to the substructure frame; and
a tank support structure coupled to the substructure, wherein the tank support structure further comprises a tank;
wherein the box-on-box land based drilling rig is adapted to be travelled in an assembled state through a wellsite.

US Pat. No. 10,036,678

AUTOMATED CONTROL OF TOOLFACE WHILE SLIDE DRILLING

NABORS DRILLING TECHNOLOG...

1. A method of slide drilling, which method comprises:determining, with a controller, using surface readings obtained adjacent a surface of a borehole, current differential pressure of a mud motor determined by calculating a difference between a measured off-bottom surface standpipe pressure and a measured on-bottom surface standpipe pressure, weight on bit (WOB) determined by a surface WOB sensor, or both;
predicting, with the controller, using the surface readings obtained adjacent the surface of the borehole, current downhole reactive torque of the mud motor based on a first predetermined relationship with either the determined current differential pressure, the WOB, or both, wherein the current downhole reactive torque is generated by sliding and causes a change in toolface orientation from a desired toolface orientation;
determining, with the controller, a downhole length of the tubular string;
determining, with the controller, based on a second predetermined relationship with the predicted current downhole reactive torque, the downhole length of the tubular string and a change of friction in the tubular string, a specific amount of surface torque, angular offset, or both to apply to a tubular adjacent the surface to counteract the current downhole reactive torque to correct for the change in toolface orientation caused by the current downhole reactive torque and to position the mud motor at the desired toolface orientation in the borehole;
generating and sending, with the controller, a control signal to a top drive to apply the specific amount of surface torque, angular offset, or both to the tubular; and
controlling, via the control signal, the top drive to apply the specific amount of surface torque, angular offset, or both to the tubular.

US Pat. No. 10,190,374

VERTICAL PIPE HANDLING SYSTEM AND METHOD

Nabors Drilling Technolog...

1. A system comprising:a cage having a pipe rack configured to store a tubular in a vertical orientation, such that a longitudinal axis of the tubular is substantially perpendicular to a horizontal plane; and
the cage having first and second robotic pipe handlers, with the first robotic pipe handler configured to transition the tubular from a horizontal orientation, in which the longitudinal axis of the tubular is substantially parallel to the horizontal plane, to the vertical orientation, wherein the first robotic pipe handler is adapted to move the tubular between the horizontal and vertical orientations by rotating about a first handler axis;
wherein the first robotic pipe handler is configured to position the tubular within the cage such that the tubular is receivable by the second robotic pipe handler after the first robotic pipe handler transitions the tubular from the horizontal orientation to the vertical orientation, and wherein the second robotic pipe handler receives the tubular into the cage through a first passage of the cage with the tubular in the vertical orientation.

US Pat. No. 10,145,187

PIPE HANDLING METHODOLOGY

NABORS DRILLING TECHNOLOG...

1. A method for positioning a pipe stand in a fingerboard having fingers with a pipe racking apparatus comprising:gripping the pipe stand with an upper grabber of the pipe racking apparatus;
gripping the pipe stand with a lower grabber of the pipe racking apparatus;
moving the pipe stand until it is aligned with a rack slot between two fingers of the fingerboard;
extending the upper and lower grabbers to position the pipe stand in the rack slot;
tilting the pipe stand in a first direction by moving one or both of the upper and lower grabbers in the first direction, the first direction perpendicular to or parallel to the fingers of the fingerboard;
lowering the pipe stand into contact with a setback of a drill floor;
tilting the pipe stand in a second direction by moving the upper grabber in the second direction, the second direction substantially parallel or substantially perpendicular to the fingers of the fingerboard, the second direction substantially perpendicular to the first direction, until the pipe stand leans against the fingerboard by a movement of the upper grabber; and
releasing the pipe stand from the upper and lower grabbers.

US Pat. No. 10,113,375

THREAD COMPENSATION APPARATUS

Nabors Drilling Technolog...

37. A method of threading tubulars, comprising:coupling a thread compensation apparatus having a drive connection interface with an outer portion and an inner rotating portion to a drive apparatus having an outer body and a rotating drive shaft, wherein the inner rotating portion is coupled to the rotating drive shaft;
coupling a tubular gripping apparatus to the thread compensation apparatus;
inserting an extending tubular into the tubular gripping apparatus, wherein the tubular gripping apparatus grips the extending tubular;
retracting an actuator of the thread compensation apparatus so as to cause the thread compensation apparatus to be in a first retracted position;
repositioning the drive apparatus in order to position the extending tubular such that an end of the extending tubular is proximal an exposed end of a top tubular of a string of tubulars;
rotating the drive shaft of the drive apparatus which imparts rotation to the inner rotating portion of the drive connection interface which thereby imparts rotation to a sleeve and the lower shaft, wherein the lower shaft further imparts rotation to the tubular gripping apparatus and the extending tubular;
threading the extending tubular to the top tubular, wherein the actuator is caused to extend to displace the lower shaft relative to the sleeve to compensate for threading displacement as the extending tubular is threaded to the top tubular; and
displacing the drive apparatus such that the weight of the string of tubulars is supported by the drive apparatus.

US Pat. No. 10,113,413

METHOD AND APPARATUS FOR DETERMINING WELLBORE POSITION

Nabors Drilling Technolog...

1. A method for determining true vertical depth along a wellbore, the method comprising:determining wellbore inclination, azimuth, and drillstring length at a plurality of static survey points, the determining wellbore inclination further comprising determining wellbore inclination from linear acceleration values determined by one or more sensors for measuring linear and gravitational acceleration;
determining inclination at a plurality of positions between two static survey points using continuous inclination measurements obtained while drilling the wellbore;
determining an interpolated azimuth value along a minimum curvature of a wellbore path at each of the plurality of positions using the azimuth values determined at the static survey points before and after each of the plurality of positions;
determining the drillstring length at each of the plurality of positions; and
using the inclination, azimuth, and measured depth values measured at the static survey points, together with continuous inclination values, corresponding interpolated azimuth values, and measured drillstring length at each of the plurality of positions between static survey points to model the wellbore path and determine a variation in true vertical depth along at least a portion of the wellbore.

US Pat. No. 10,094,175

TORQUE TRACK SYSTEM

Nabors Drilling Technolog...

1. A system, comprising:a torque track system configured to couple to a derrick and to a top drive of a drilling rig, wherein the torque track system is configured to resist movement of the top drive in a lateral direction with respect to the derrick and to transfer torsional loads to the derrick in an operating configuration;
a first torque track segment of the torque track system;
a second torque track segment of the torque track system; and
a joint coupling the first torque track segment to the second torque track segment, wherein the joint comprises:
a knuckle configured to enable the first torque track segment and the second torque track segment to pivot with respect to one another while maintaining a physical connection between the first torque track segment and the second torque track segment during manipulation of the torque track system into and out of the operating configuration;
a first connector coupled to a first end of the first torque track segment;
a first opening formed when the knuckle is disposed in a first groove of the first connector, wherein the first opening extends through the first connector and the knuckle;
a second opening formed when the knuckle is disposed in the first groove of the first connector, wherein the second opening extends through the first connector and the knuckle;
a first fastener configured to be disposed in the first opening; and
a second fastener configured to be disposed in the second opening,
wherein:
each of the first and second fasteners is configured to enable rotation of the first torque track segment with respect to the second torque track segment when the other of the first and second fasteners is not disposed in the first or second opening, respectively, and
the first and second fasteners are configured to substantially block rotation of the first torque track segment with respect to the second torque track segment when the first and second fasteners are disposed in the first and second openings, respectively.

US Pat. No. 10,214,936

SIDE SADDLE SLINGSHOT DRILLING RIG

NABORS DRILLING TECHNOLOG...

1. A drilling rig comprising:a right substructure and a left substructure, the substructures positioned generally parallel and spaced apart from each other;
the right substructure comprises a right lower box and a first strut, the first strut pivotably coupled to a drill rig floor and pivotably coupled to the right lower box, the drill rig floor including a V-door, the side of the drill rig floor including the V-door defining the V-door side of the drill rig floor, the V-door oriented to face perpendicular to the right substructure;
the left substructure comprises a left lower box and a second strut, the second strut pivotably coupled to the drill rig floor and pivotably coupled to the left lower box;
a cylinder sub box, the cylinder sub box including one or more mast hydraulic cylinders, the cylinder sub box coupled to the left substructure at a side of the left substructure or to the right substructure at a side of the right substructure; and
a mast, the mast including an open side defining a mast V-door side, the open side oriented to face perpendicular to the right substructure, the mast pivotably coupled to the drill rig floor by one or more pivot points and one or more lower mast attachment points, the mast being pivotable in a direction perpendicular to the V-door side of the drill rig floor.

US Pat. No. 10,214,937

SLINGSHOT SIDE SADDLE SUBSTRUCTURE

Nabors Drilling Technolog...

2. A land-based drilling rig comprising:a first substructure;
a second substructure, the second substructure being positioned generally parallel to the first substructure;
a drill rig floor fixedly coupled to the first and second substructures wherein the drill rig floor is immovable with respect to the first and second substructures when the land-based drilling rig is assembled and set up for drilling, the drill rig floor including a V-door, the side of the drill rig floor having the V-door defining a V-door side of the drill rig floor, the V-door side of the drill rig floor parallel to the first substructure;
a mast, the mast mechanically coupled to one or more of the first substructure, the second substructure, and the drill rig floor, the mast being pivotably coupled to one or more of the first substructure, the second substructure, and the drill rig floor by a mast pivot point, the mast comprising a V-door side, the V-door side of the mast parallel to the first or second substructure;
a mast hydraulic lift cylinder coupled to the mast at a mast lift point; and
a choke manifold, the choke manifold positioned on the drill rig floor.

US Pat. No. 10,174,570

SYSTEM AND METHOD FOR MUD CIRCULATION

Nabors Drilling Technolog...

1. A pipe drive system, comprising:a gripping device configured to couple with a pipe element;
a sealing mechanism comprising a seal disposed between the gripping device and the drill pipe element;
a strain gauge disposed on the seal and adapted to measure seal pressure;
a pump configured to pump a drilling fluid flow through the gripping device and the pipe element while the pipe element is being installed into or removed from a wellbore; and
a controller configured to regulate a flow rate of the drilling fluid flow while the pipe element is being installed into or removed from the wellbore based on one or more operating parameters associated with installing or removing the pipe element from the wellbore, the one or more operating parameters, comprising the seal pressure.

US Pat. No. 10,150,659

DIRECT DRIVE DRAWWORKS WITH BEARINGLESS MOTOR

NABORS DRILLING TECHNOLOG...

1. A direct drive hoist, comprising:an electric motor,
a first motor mount, the first motor mount adapted to couple the electric motor to a surface, the first motor mount including a damping assembly adapted to allow damped movement between the electric motor and the surface, the first motor mount including an adjusting assembly adapted to extend or retract the first motor mount;
a shaft extending through electric motor wherein there is no bearing between the electric motor and the shaft, the shaft adapted to be rotated by the electric motor; and
a load connected to the shaft, the load adapted to be rotated by the shaft as the shaft is rotated by the electric motor.

US Pat. No. 10,138,722

WELL PROTECTION SYSTEMS AND METHODS

Nabors Drilling Technolog...

1. A method, comprising:tracking, automatically by a controller of a drilling rig, a position of a bit at a distal end of a bottom hole assembly coupled to a drill string of the drilling rig during a surge or swab operation through a wellbore environment of a wellbore;
determining, automatically by the controller at a first time during the surge or swab operation, the wellbore environment comprises a first wellbore environment from the tracked position of the bit based on at least one received drilling parameter relating to the drill string in the wellbore;
adjusting, dynamically by the controller during the surge or swab operation, a trip speed of the drill string to a first trip speed based on the determined first wellbore environment;
determining, automatically by the controller at a second time during the surge or swab operation, the wellbore environment comprises a second wellbore environment from the tracked position of the bit based on the at least one received drilling parameter relating to the drill string in the wellbore; and
adjusting, dynamically by the controller during the surge or swab operation, the trip speed of the drill string to a second trip speed based on the determined second wellbore environment.

US Pat. No. 10,107,046

ARTICULATING GRASSHOPPER ARM

NABORS DRILLING TECHNOLOG...

1. A system comprising:a drilling rig, the drilling rig having a mast;
an articulating grasshopper arm, the articulating grasshopper arm comprising a cable tray, the cable tray pivotably coupled to the drilling rig by a secondary frame, the secondary frame coupled between the cable tray and the drilling rig, the secondary frame pivotably coupled to the drilling rig by at least one frame pivot point, the at least one frame pivot point adapted to allow the secondary frame to pivot laterally left and right relative to the drilling rig, the cable tray pivotably coupled to the secondary frame by at least one cable tray pivot point, the at least one cable tray pivot point adapted to allow the cable tray to pivot upward and downward relative to the secondary frame, the secondary frame adapted to allow the cable tray to pivot upward and downward as well as laterally right and left relative to the drilling rig; and
a brace coupled between the cable tray and the secondary frame, the brace having a first end pivotably coupled to the cable tray and a second end that is releasably slidably connected to the secondary frame.

US Pat. No. 10,107,089

TOP DRIVE MOVEMENT MEASUREMENTS SYSTEM AND METHOD

NABORS DRILLING TECHNOLOG...

1. A top drive system; comprising:a top drive movement measurement system, comprising:
a saver sub configured to couple to the top drive system;
an annular housing disposed about the saver sub;
a first plurality of sensors disposed within the annular housing, wherein the first plurality of sensors is configured to detect lateral movement of the saver sub of the top drive system, wherein the first plurality of sensors comprises a linear accelerometer and a gyroscope;
a second plurality of sensors disposed about an outer circumference of the saver sub, wherein the second plurality of sensors is configured to detect one or more compression or tension forces on the saver sub of the top drive system, wherein the second plurality of sensors comprises a plurality of strain gauges, wherein the plurality of strain gauges are spaced equidistantly about the outer circumference of the saver sub; and
one or more non-transitory, computer-readable media having executable instructions stored thereon, the executable instructions comprising instructions configured to detect circular or oblong movement of the saver sub of the top drive system based on combined data collected by the first plurality of sensors, the second plurality of sensors, or both, and instructions configured to generate an alert upon detection of the circular or oblong movement, wherein the detection of the circular or the oblong movement comprises the first plurality of sensors detecting lateral movement that exceeds a first threshold and the second plurality of sensors detecting compression and tension forces that exceed a second threshold, wherein the one or more non-transitory, computer-readable media comprises at least one first value and at least one second value stored thereon, wherein the at least one first value corresponds to the first threshold value and the at least one second value corresponds to the second threshold value.

US Pat. No. 10,214,970

POST AND NON-ELONGATED SUBSTRUCTURE DRILLING RIG

NABORS DRILLING TECHNOLOG...

1. A land-based drilling rig comprising:a drill rig floor, the drill rig floor including a V-door, a side of the drill rig floor having the V-door defining a V-door side of the drill rig floor and an opposite V-door side of the drill rig floor opposite the V-door side of the drill rig floor;
a mast, the mast mechanically coupled to the drill rig floor; and
at least four support bases, each support base coupled to the drill rig floor by a telescoping support arm, the support base and telescoping arm forming a support, wherein the support bases are polyhedrons having a square base or are cylindrical and
wherein the support bases are arranged in a V-door support row and an opposite V-door support row, each row of support bases having at least three support bases, the V-door support row arranged along the V-door side of the drill rig floor and the opposite V-door support row arranged opposite the V-door side of the drill rig floor or
wherein the V-door is positioned between at least two supports, each of the supports is positioned at or near edges of the drill rig floor, and an opening distance between two adjacent supports is A and an opening distance between two other adjacent supports is A?, wherein A and A? are greater than the diameter of a wellhead.

US Pat. No. 10,215,010

ANTI-WHIRL SYSTEMS AND METHODS

NABORS DRILLING TECHNOLOG...

1. A system, comprising:a controller configured to:
collect downhole lateral vibration, weight on bit (WOB), and differential pressure (DP) or annular pressure data,
determine a natural frequency of a drill string in a lateral motion;
determine a correlative relationship between:
(1) lateral stiffness (k) and WOB, and
(2) lateral viscous damping (?) and DP or annular pressure,
model a forward whirl region using the determined relationships for (1) and (2),
generate a control algorithm for top drive RPM and WOB that avoids the forward whirl region,
determine a top drive RPM supervisory set point for a particular WOB using the control algorithm, and
provide one or more operational control signals that limit the top drive RPM to the top drive RPM supervisory set point for the particular WOB; and
a drive system configured to:
receive the one or more operational control signals from the controller, and
limit the top drive RPM so that the top drive RPM does not exceed the top drive supervisory set point for the particular WOB.

US Pat. No. 10,107,036

ROTARY TRANSFORMER FOR POWER TRANSMISSION ON A DRILLING RIG SYSTEM AND METHOD

Nabors Drilling Technolog...

18. A method for providing power to a component on a drilling rig, comprising:transmitting a first electric current from a power source to a primary coil coupled to a first component of the drilling rig to generate a magnetic flux through the primary coil and through a secondary coil, wherein the secondary coil is disposed proximate to the primary coil and coupled to a second component of the drilling rig, wherein the second component is configured to rotate relative to the first component, and wherein the magnetic flux through the secondary coil induces a second electric current in the secondary coil;
transmitting the second electric current from the secondary coil to the second component or to a third component configured to rotate with the second component; and
actuating a mud valve at or coupled to the second component or the third component using the second electric current, wherein the actuation of the mud valve is configured to enable or disable a flow of fluid through the first component, the second component, the third component, or any combination thereof.

US Pat. No. 10,309,167

TUBULAR HANDLING DEVICE AND METHODS

Nabors Drilling Technolog...

1. A method of handling a tubular in a casing or drilling operation, comprising:grasping the tubular with a tubular member elevator coupled with an actuator, the tubular having an axial end;
orienting the tubular relative to a running tool based on the actuator pivoting the tubular from a first position out of alignment with an axis parallel to a centerline of the running tool to a second position in alignment with the axis;
retracting the actuator coupled to the tubular member elevator to cause at least a tubular section at the axial end of the tubular to move along the axis to enter the running tool;
operating the running tool to frictionally engage and grip the tubular section, the tubular section being retained solely in response to a force created by a weight of the tubular interacting with the running tool; and
applying a rotational force to the tubular section while it is engaged and gripped by the running tool to connect the tubular to a tubular string.

US Pat. No. 10,280,692

SLINGSHOT SIDE SADDLE SUBSTRUCTURE

NABORS DRILLING TECHNOLOG...

10. A method comprising:positioning a first and second lower box generally parallel and spaced apart from each other;
coupling a drill rig floor to the first lower box by a first strut, the first lower box and first strut defining a first substructure, the drill rig floor including a V-door, the V-door oriented perpendicularly to a long axis of one of the substructures;
coupling the drill rig floor to the second lower box by a second strut, the second lower box and second strut defining a second substructure, the struts hingedly coupled to the drill rig floor and hingedly coupled to the corresponding lower box;
pivoting the drill rig floor between an upright and a lowered position using a first and second hydraulic cylinders, the first and second hydraulic cylinders connected to the lower boxes;
pivoting the drill rig floor between the lowered position and the upright position using the first and second hydraulic cylinders; and
coupling diagonals between the drill rig floor and first and second substructures.

US Pat. No. 10,267,108

PLUG LAUNCHING SYSTEM AND METHOD

Nabors Drilling Technolog...

12. A method, comprising:directing a cement flow through an annulus between a plug canister and a main body of a plug launching system;
directing the cement flow from the annulus to a central passage of the plug canister through a first plurality of openings extending through the plug canister, wherein the first plurality of openings are disposed axially below a first plug disposed within the plug canister;
directing the cement flow from the central passage into a casing string disposed within a wellbore;
rotating a first rotary sleeve of the plug canister about a central axis of the plug canister to occlude the first plurality of openings; and
re-directing the cement flow from the annulus to the central passage of the plug canister through a second plurality of openings extending through the plug canister, wherein the second plurality of openings are disposed axially above the first plug.

US Pat. No. 10,260,331

AUTODRILLING CONTROL WITH ANNULUS PRESSURE MODIFICATION OF DIFFERENTIAL PRESSURE

Nabors Drilling Technolog...

1. An apparatus, comprising:a transceiver configured to:
receive a differential pressure measurement of a mud flow in a drilling rig from a differential pressure sensor; and
receive an annulus pressure measurement of pressure in a vicinity to a bottom hole assembly of the drilling rig from an annulus pressure sensor; and
a controller configured to:
receive the differential pressure measurement and the annulus pressure measurement from the transceiver;
modify the differential pressure measurement with the annulus pressure measurement; and
control a rate of penetration of the bottom hole assembly with the modified differential pressure measurement.

US Pat. No. 10,246,950

DEADLINE COMPENSATOR

Nabors Drilling Technolog...

1. A deadline compensator, comprising:a compensator assembly configured to engage a deadline between a crown block and a supply reel, wherein the compensator assembly is configured to transition between a first position and a second position;
at least one compensator sheave of the compensator assembly, wherein the compensator sheave is configured to engage the deadline;
at least one actuator of the compensator assembly, wherein the actuator is configured to apply a force to the deadline via the at least one compensator sheave to displace the deadline while the compensator assembly is in the first position and configured to retract into the second position in response to a second load condition on the deadline; and
a sensor engaged to the deadline configured to detect a tension force of the deadline, wherein the sensor communicates a first signal to a controller, and the controller communicates a second signal to the compensator assembly to transition the compensator assembly between the first position and the second position in response to the first signal.

US Pat. No. 10,329,857

OILFIELD TUBULAR SPIN-IN AND SPIN-OUT DETECTION FOR MAKING-UP AND BREAKING-OUT TUBULAR STRINGS

NABORS DRILLING TECHNOLOG...

1. A method for making up a threaded connection between an upper tubular and a lower tubular using a low-torque oilfield tubular spinner and a high-torque torque wrench, the low-torque and high-torque being relative to each other, the method comprising:holding the lower tubular with the high-torque torque wrench;
frictionally engaging the upper tubular with the low-torque tubular spinner;
operating a motor of the low-torque tubular spinner to spin-in and shoulder-up a tubular connection between the upper tubular and the lower tubular;
establishing a threshold hydraulic system pressure that indicates a shouldered-up condition, wherein the threshold hydraulic system pressure is substantially equal to a maximum hydraulic system pressure;
monitoring, with a detection system, a hydraulic system pressure of the motor during spin-in and shoulder-up;
detecting the shouldered-up condition, with the detection system, when the maximum hydraulic system pressure is substantially reached; and
maintaining the threshold hydraulic system pressure to operate the motor for a selected period of time when the threshold hydraulic system pressure is reached.

US Pat. No. 10,316,640

SYSTEMS AND METHODS FOR PRESSURE TESTING WELL CONTROL EQUIPMENT

NABORS DRILLING TECHNOLOG...

1. A well production system comprising:a blowout preventer stack (BOP) configured to be positioned on a wellhead or a test stump, the blowout preventer stack comprising a blowout preventer valve through which pressurized fluid and gas can exit a well;
a choke manifold comprising a plurality of fluid lines through which the pressurized fluid and gas may flow, the choke manifold comprising a plurality of valves selectively controllable to permit or prevent the pressurized fluid and gas from passing through the manifold;
a choke conduit extending from and in fluid communication with the choke manifold, the choke conduit being arranged to carry the pressurized fluid and gas to the choke manifold; and
a pressure testing tool disposed in selective fluid communication with the blowout preventer stack and the choke conduit and being arranged to permit independent pressure testing of valves of the blowout preventer stack and valves of the choke manifold without breaking connections between the blowout preventer stack and the choke manifold and without the need to add additional valves to the system if connections are disconnected, the pressure testing tool comprising:
a fluid passage sized and configured to carry pressurized fluid and gas from the blowout preventer stack to the choke conduit when the well production system is an operational use;
a blowout preventer valve disposed between the fluid passage and the blowout preventer stack, the blowout preventer valve being operable to selectively place the blowout preventer stack in fluid communication with the passage,
a choke manifold valve disposed between the fluid passage and the choke manifold, the choke manifold valve being operable to selectively place the choke conduit in fluid communication with the passage; and
a test valve disposed between the fluid passage and an atmosphere, the test valve being operable to selectively open the fluid passage to one of the atmosphere and to a pressure measuring indicator.