A floating drift apparatus for verifying the inner diameter of tubulars as the tubulars are made up into a tubular string being run into a wellbore. A float section provides buoyancy to float the apparatus in fluid within the bore of a tubular, and a drift section has a drift element with a diameter substantially equal to the tubular inner diameter being verified, which may be the drift diameter. When running a tubular string, the apparatus is inserted into the bore of the tubular string, floating in the fluid. As joints of tubular are made up and run into the wellbore, the tubulars move downhole around the apparatus. Preferably, the floating drift apparatus can be visually detected. If an undersize ID is encountered, the floating drift apparatus will be pushed downhole and no longer visible; the operator can remove the undersize ID tubular from the string.

A vibration isolating coupler including a first coupler portion, a second coupler portion including an external surface and an internal surface portion, and a vibration isolating portion extending between the first coupler portion and the second coupler portion. The vibration isolating portion including a first solid annular portion and a second solid annular portion. The vibration isolating portion including a plurality of slots extending from the first solid annular portion toward the second solid annular portion forming a plurality of vibration isolating elements. Each of the plurality of vibration isolating elements is disconnected from adjacent ones of the plurality of vibration isolating elements by a corresponding one of the plurality of slots. The plurality of vibration isolating elements enabling torsional rotation of the first coupler portion relative to the second coupler portion.

A tubular string includes a first tubular member with a pin end with pin threads and a pin external load shoulder. The tubular string also includes a second tubular member with a box end with a box external load shoulder and box threads, the pin threads being threadable into the box threads to form a connection, wherein the pin external load shoulder has an outer diameter (OD) that is different than an OD of the box external load shoulder. A load distribution sleeve is locatable between the first and second tubular members when threaded together and includes a first end facing the first tubular member and a second end facing the second tubular member, wherein the ODs of the load distribution sleeve first and second ends match the ODs of the pin and box external load shoulders respectively. The load distribution sleeve contacts the pin and box external load shoulders and distributes a make-up load between the pin and box external load shoulders when the connection is made up.

A protector for the male or female end of a threaded tubular connection for drilling or operating hydrocarbon wells, comprising a principal body, a first sealing gasket formed from a material which is less rigid than the material of the protector body and intended to make a seal with a surface of an end of the component, the principal body comprising a plurality of orifices through which the sealing gasket passes.

A protector for a connection for a tubular component for drilling or operating hydrocarbon wells, provided with a distal end surface, the protector comprising an annular housing comprising a bottom, two lateral walls, outer and inner, separated from each other and in which an annular gasket is disposed, each lateral wall comprising a bottom lateral wall portion and an exterior lateral wall portion and an upper face, the two exterior lateral wall portions defining an opening with width A.sub.u and characterized in that a distance A between two bottom lateral wall portions is greater than the width A.sub.u, in a manner such as to allow a first annular gasket to be positioned then to allow said annular gasket to be retained in the annular housing.

An apparatus for drilling a borehole in an earth formation includes: a plurality of drill pipes configured to be coupled together to form a drill string that is configured to convey an earth formation disintegrating device while progressing into the earth formation; a communication medium disposed on the drill string and configured to communicate a signal; and one or more processors. The one or more processors are configured to: receive drilling information; determine a stress distribution along at least a part of the drill string using the drilling information; determine a cumulative fatigue damage of at least a part of one drill pipe in the drill string using the stress distribution; and write the cumulative fatigue damage of the at least a part of one drill pipe to a memory.

A washing and doping mechanism includes a bushing that is configured to engage a tubular that is in a substantially vertical orientation. The bushing is configured to rotate, thereby causing the tubular to rotate about a central longitudinal axis of the tubular. The washing and doping mechanism also includes a sprayer configured to spray a fluid onto the tubular in the substantially vertical orientation.

A downhole protection apparatus, for use in protecting downhole control lines, comprises a sheath defining a channel configured to receive a control line. The sheath is configured to be attached to a tubing. In wellbore applications, the control lines associated with a tubing are inserted into the sheath such that the body of the sheath at least partially encompasses the control line and shields the control line from harsh downhole conditions which may include abrasive action from sand, proppants, wellbore cuttings and other debris. Therefore, the apparatus is configured such that after insertion of a control line into the channel, a body of the sheath protects the control line from an outside environment.

A system for blocking rotation between a first tubular and a second tubular includes a key positioned within a recess formed in the first tubular. The system also includes a retention fastener securing the key to the first tubular, the retention fastener being arranged within an elongated aperture extending through the key. The system further includes an installation fastener moving the key from a storage configuration when in a first position to an engaged configuration when in a second position, the installation fastener having a tapered face that engages at least a portion of the key. The system also includes teeth arranged along a bottom portion of the key, proximate the second tubular, the teeth engaging the second tubular via rotation of the key about the retention fastener and blocking rotation of the first tubular relative to the second tubular in a first direction.

A hand-held OCTG length measuring apparatus has hollow upper and lower bodies, a hand grip extending generally downward from the hollow upper body near the first end and including a source trigger, and a sensor housing extending generally downward from the hollow upper body. The sensor housing encloses a TOF source operatively connected to the source trigger. The hollow lower body shaped to include a frontal cavity positioned generally under the source housing, the frontal cavity having attached thereto a pipe end alignment bracket. The upper hollow body and the lower hollow body connected at a lower end of the hand grip and at a lower end of the sensor housing. The apparatus employs a minimum 40,000 lux laser (at 18 to 25 feet) and a polarized, diamond-grade reflector, to afford reliable, repeatable OCTG length measurements.