Abstract: A method for selecting a bottomhole assembly, including performing a first dynamic simulation of a first bottomhole assembly, performing at least a second dynamic simulation of the first bottomhole assembly, in which the at least a second dynamic simulation includes a different constraint than the first dynamic simulation, and outputting results for both the first dynamic simulation and the second dynamic simulation, in which the results include at least one output showing performance as a function of position along the bottomhole assembly.

Abstract: Techniques for optimizing automated drilling processes are disclosed. Such techniques include modeling a formation and selecting a drilling trajectory in the formation. Measurements of rate of penetration (ROP), revolutions per minute (RPM), weight-on-bit (WOB) and torque-on-bit (TOB) of a drilling string at a position on the drilling trajectory in the formation are received. A functional relationship between depth of cut (DOC), WOB, and TOB for the modeled formation is determined. Operating constraints defining a safe operating envelope as a function of RPM and WOB along the selected drilling trajectory are determined, and an optimal RPM and WOB is determined based on operating constraints. A cost function of RPM and WOB is determined, and a path from current RPM and WOB to optimal RPM and WOB is determined based on the cost function.

Abstract: A method for determining a drilling state of a bottom hole assembly in a wellbore includes acquiring one or more downhole sensor measurements and processing the sensor measurements using a downhole processor to determine a drilling state of the bottom hole assembly. An operating state of the bottom hole assembly may be automatically changed in response to the determined drilling state. A method for computing a dynamic drilling energy of a bottom hole assembly includes acquiring at least one sensor measurement and processing the sensor measurements to obtain at least one of (i) an energy of axial motion of the bottom hole assembly, (ii) an energy of rotational motion of the bottom hole assembly, and (iii) an energy of lateral motion of the bottom hole assembly.

Abstract: Techniques for optimizing automated drilling processes are disclosed. Such techniques include modeling a formation and selecting a drilling trajectory in the formation. Measurements of rate of penetration (ROP), revolutions per minute (RPM), weight-on-bit (WOB) and torque-on-bit (TOB) of a drilling string at a position on the drilling trajectory in the formation are received. A functional relationship between depth of cut (DOC), WOB, and TOB for the modeled formation is determined. Operating constraints defining a safe operating envelope as a function of RPM and WOB along the selected drilling trajectory are determined, and an optimal RPM and WOB is determined based on operating constraints. A cost function of RPM and WOB is determined, and a path from current RPM and WOB to optimal RPM and WOB is determined based on the cost function.

Abstract: A method for selecting a bottomhole assembly, including performing a first dynamic simulation of a first bottomhole assembly, performing at least a second dynamic simulation of the first bottomhole assembly, in which the at least a second dynamic simulation includes a different constraint than the first dynamic simulation, and outputting results for both the first dynamic simulation and the second dynamic simulation, in which the results include at least one output showing performance as a function of position along the bottomhole assembly.

Abstract: A method for determining a drilling state of a bottom hole assembly in a wellbore includes acquiring one or more downhole sensor measurements and processing the sensor measurements using a downhole processor to determine a drilling state of the bottom hole assembly. An operating state of the bottom hole assembly may be automatically changed in response to the determined drilling state. A method for computing a dynamic drilling energy of a bottom hole assembly includes acquiring at least one sensor measurement and processing the sensor measurements to obtain at least one of (i) an energy of axial motion of the bottom hole assembly, (ii) an energy of rotational motion of the bottom hole assembly, and (iii) an energy of lateral motion of the bottom hole assembly.

Abstract: Torsional, axial and lateral vibrations introduced when a mud motor is used with a drilling tool to drill a borehole are calculated using a model. The model includes different computational modules for each of three distinct motor sections: power, transmission and bearing. The resulting calculated vibration effects are used to enhance the drilling tool and drilling operation.

Abstract: The present invention recites a drill bit comprising a main body having an axis about which it is rotated in use, a cutting face, a connecting means for attaching the bit to a source of rotary motion, a gauge region intermediate said cutting face and the connecting means. Additionally the gauge region comprises at least one member movable between a first position in which the gauge region is bounded by an imaginary tubular surface of constant cross-section co-axial to the axis of rotation and a second position in which a portion of the member is located radially inwards, with respect to the axis of rotation, of its position when said member is in said first position. In accordance with the present invention, the gauge region whilst said member is in said second position being bound by an imaginary three dimensional conical sectional surface; and at least one actuator.

Abstract: Torsional, axial and lateral vibrations introduced when a mud motor is used with a drilling tool to drill a borehole are calculated using a model. The model includes different computational modules for each of three distinct motor sections: power, transmission and bearing. The resulting calculated vibration effects are used to enhance the drilling tool and drilling operation.

Abstract: A method includes sensing a parameter in a well using a sensor disposed on a drillstring, determining a position of the sensor in a wellbore based on a position of the sensor in the drillstring and a position of the drillstring in the wellbore.

Abstract: A drill bit 10 comprising a main body 22 having an axis about which it is rotated in use; a cutting face 12, connecting means 16 for, in use, attaching the bit to a source of rotary motion; a gauge region 18 intermediate said cutting face 12 and said connecting means 16, said gauge region 18 comprising at least one member 20, 32 movable between a first position in which the gauge region is bounded by an imaginary tubular surface of constant cross-section co-axial to the axis of rotation; and a second position in which a portion of the member is located radially inwards, with respect to the axis of rotation, of its position when said member is in said first position, the gauge region whilst said member is in said second position being bound by an imaginary three dimensional conical sectional surface; and at least one actuator 24, 36.