Abstract: A downhole tool is provided for measuring accelerations at a location within a subterranean borehole. The tool is rotatable around the longitudinal direction of the borehole. The tool includes four accelerometers, each accelerometer measuring acceleration in a respective direction and being arranged such that at least a component of its measured acceleration is normal to the longitudinal direction. The accelerometers are further arranged such that no more than any two of the four accelerometers have their respective components parallel to the same direction. The tool also includes a first device which measures the rotational speed of the tool. The tool also includes a processor unit which relates the acceleration measured by each accelerometer to the true acceleration at that accelerometer by a respective scaling term and a respective offset, and combines the measured accelerations and the tool rotational speed to re-calibrate the scaling terms as the tool rotates.

Abstract: A downhole tool for measuring angular positions at a location within a subterranean borehole. The tool is rotatable around the longitudinal direction of the borehole. The tool includes two or more magnetometers which measure the Earth's magnetic field along respective magnetometer axes. Each magnetometer is arranged such that its measurement includes a component of the Earth's magnetic field normal to the longitudinal direction of the borehole. The magnetometers are further arranged such that these normal components are at an angle to each other around the longitudinal direction. The tool further includes a device which measures the rotational speed of the tool or the time derivative thereof. The tool includes a processor unit that calculates angular positions of the downhole tool around the longitudinal direction relative to the direction of the Earth's magnetic field from the measurements of the Earth's magnetic field and the tool rotational speed or time derivative thereof.

Abstract: A bottomhole assembly for performing a wellbore operation comprising a plurality of full-gauge components that are each radially expandable and retractable between respective first positions and respective second positions, wherein the first positions each have a diameter which is substantially the same as that of the wellbore and wherein the second positions each have a diameter which is substantially smaller than that of the wellbore. The plurality of full-gauge components comprise a full-gauge drill bit and one or more full-gauge stabilizers. The bottomhole assembly may further comprise a rotary steerable system and/or a motor.

Abstract: Systems and methods for drilling a wellbore. The method includes measuring a first distance that a drilling device is raised while connected to a drill string, determining a weight-on-bit in the drill string, determining a second distance to lower the drilling device such that a drill bit at a lower extremity of the drill string approaches toward a bottom of the wellbore, based on the first distance and the weight-on-bit, and lowering the drilling device by the second distance.

Abstract: A method for determining hydraulic compliance of a wellbore during a managed pressure drilling procedure. Measurements are made of the pressure of a drilling fluid being circulated in the wellbore during the procedure at the top of a drilling annulus, the flow rate qin of the drilling fluid into the wellbore and the flow rate qout of the fluid out of the wellbore. These three measurements are used to determine the difference of the flow rates and a discrete time derivative (Pt?Pt-?t)/?t of the pressure, where t is time and ?t is a time interval. The differences in flow rates and the time derivatives are then processed by applying a low pass filter to determine the hydraulic compliance of the wellbore.

Abstract: Pipes, drill strings including pipes, and methods for use on a drilling rig. The method includes obtaining pipe data for individual drill pipes of a drill string, obtaining a well trajectory for a well, obtaining one or more drilling measurements to be used when drilling the well, planning a first drill string based on the pipe data, the well trajectory, and the one or more drilling measurements, predicting an aging of the individual drill pipes in the first drill string while drilling the well using the first drill string, determining that a risk of failure of one or more individual pipes in the first drill string is unacceptable based on the aging of the individual pipes; and planning a second drill string in response to determining that the risk of failure is unacceptable in the first drill string.

Abstract: A method for changing a set point of a system where period of a dominant resonance of the system is determined, a change profile for the set point change is processed; a time period for the set point change based on the period of the dominant resonance in order to minimize excitation of the dominant resonance is also processed; and the set point change is actioned according to the processed change profile and the time period.

Abstract: An apparatus for drilling a wellbore (10) is disclosed, the apparatus comprising a lowermost pilot drill bit (16) having a diameter less than that of the diameter of wellbore (12) drilled by the apparatus, above which is a reamer, having an adjustable drill diameter from a first diameter less than that of the pilot drill to a second diameter greater than that of the pilot drill, above which is a body portion (24) having a lower diameter less than that of the pilot drill and an upper diameter greater than that of the pilot' drill but less than the second diameter of the reamer.

Abstract: A method for controlling a drilling system comprising a drive system, drillstring and drill bit. The drive system rotates the drillstring during a drilling process to drill a borehole through an earth formation. The method involves setting a desired rotation speed v0 for the drillstring; receiving property measurements of the drilling system and deriving therefrom the component vup of the rotation speed of the drillstring associated with upgoing rotational energy; determining a rotation speed v for the drillstring by optimizing an expression which reconciles two conflicting objectives of: (i) maintaining a stable rotation speed centred on v0, and (ii) minimizing the downgoing rotational energy, the optimized expression expressing v in terms of v0 and vup; and controlling the drive system to rotate the drillstring at v.

Abstract: A communication system for communicating information with a compliant medium is disclosed, the communication device includes a constrained fluid, a valve, a modulator, a sensor and a demodulator. The constrained is fluid distributed along a length. The valve is configured to operatively engage a second point relative to the length. The modulator configured to actuate the valve according to information. The sensor configured to measure pressure at a first point relative to the length, where the first point is distant from the second point. The demodulator is coupled to the sensor to recover the information.

Abstract: A subpart of a drill string is described having an outer circumferential surface which is contoured and adapted to engage the wall of the borehole with a small angle of attack while exerting during rotary drilling operations an compacting pressure on mud cake and/or cuttings present in the annulus between the drill string and the borehole.

Abstract: A system and method is provided for drilling a wellbore using a rotary drill bit with a bit body having a plurality of mechanical cutters to cut away formation material as the wellbore is formed; and a directed energy mechanism to direct energy into the formation. The energy from the directed energy mechanism is used to enhance the cutting of the mechanical cutters by fracturing surrounding material to facilitate drilling in the direction of the directed energy.

Abstract: An apparatus for drilling a wellbore (10) is disclosed, the apparatus comprising a lowermost pilot drill bit (16) having a diameter less than that of the diameter of wellbore (12) drilled by the apparatus, above which is a reamer, having an adjustable drill diameter from a first diameter less than that of the pilot drill to a second diameter greater than that of the pilot drill, above which is a body portion (24) having a lower diameter less than that of the pilot drill and an upper diameter greater than that of the pilot' drill but less than the second diameter of the reamer.

Abstract: A system and method is provided for drilling a wellbore using a rotary drill bit with a bit body having a plurality of mechanical cutters to cut away formation material as the wellbore is formed and a directed energy mechanism to direct energy into the formation. The energy from the directed energy mechanism is used to enhance the cutting of the mechanical cutters by fracturing surrounding material to facilitate drilling in the direction of the directed energy.

Abstract: A subpart of a drill string is described having an outer circumferential surface which is contoured and adapted to engage the wall of the borehole with a small angle of attack while exerting during rotary drilling operations an compacting pressure on mud cake and/or cuttings present in the annulus between the drill string and the borehole.

Abstract: A subpart of a drill string is described having an outer circumferential surface which is contoured and adapted to engage the wall of the borehole with a small angle of attack while exerting during rotary drilling operations an compacting pressure on mud cake and/or cuttings present in the annulus between the drill string and the borehole.

Abstract: Methods and system are described for providing electric power in a wellbore including at least one thermoelectric generator at a downhole location; and one or more thermally insulated sections of wellbore tubing located such as to reduce heat loss of fluid flowing through the wellbore from the entry point of the fluid to the location of the generator.

Abstract: The present invention provides a seismic surveying method in which vibrators in a first vibrator group are actuated at time T0 and vibrators in a second vibrator group are actuated at time T1, where T0<T1<T0+S1+L and S1 is the sweep time of the first group and L is the listening time. This method enables the time required to complete a seismic survey to be reduced. In other embodiments, vibrators in the first vibrator group may be actuated at time T2, where T1<T2<T1+S2+L and S2 is the sweep time of the first group, and vibrators in the second vibrator group at time T3 where T2<T3<T2+S1+L and T3?T2?T1?T0. Such embodiments providing that by appropriately combining the shot records noise may be eliminated.

Abstract: A method enables the time required to complete a seismic survey and the noises recorded in the seismic data to be reduced. One aspect of the method includes actuating a first vibrator group to start a first sweep at time T0; and a second vibrator group to start a second sweep at time T1, wherein T0<T1<T0+S1+L, where S1 is a sweep time of the first vibrator group and L is a listening time; wherein the time between the first sweep and the second sweep is T1?T0?((n?1)*f1*S1)/(n*(f1?f0)) where n is a natural number, f0 is the lower frequency limit of the vibrator sweep and f1 is the upper frequency limit of the vibrator sweep.

Abstract: A method enables the time required to complete a seismic survey and the noises recorded in the seismic data to be reduced. One aspect of the method includes actuating a first vibrator group to start a first sweep at time T0; and a second vibrator group to start a second sweep at time T1, wherein T0<T1<T0+S1+L, where S1 is a sweep time of the first vibrator group and L is a listening time; wherein the time between the first sweep and the second sweep is T1?T0?((n?1)*f1*S1)/(n*(f1?f0)) where n is a natural number, f0 is the lower frequency limit of the vibrator sweep and f1 is the upper frequency limit of the vibrator sweep.