A diameter measurement device for measuring the diameter of a wireline cable dynamically during moving in and out of a borehole. The measurement device has a first pair of opposed shafts, a rotating roller on each shaft of said first pair of opposed shafts, a first resilient member mounted to urge at least one of the shafts of said first pair of opposed shafts toward the wireline cable to be measured, and a first intrinsic measuring unit operatively associated with the first resilient member to measure the displacement thereof. The measuring device further has at least a second pair of opposed shafts angularly displaced with respect to the first pair of opposed shafts, a rotating roller on each shaft of said second pair of opposed shafts, a second resilient member mounted to urge at least one of the shafts of said second pair of opposed shafts toward the wireline cable to be measured, and a second intrinsic measuring unit operatively associated with the first resilient member to measure the displacement thereof as the wireline cable is moved lengthwise between the rollers; each of said first and second intrinsic measuring devices outputting to a digitizer for generating digital measurements of the diameter at various positions on the circumference of and along the length of said wireline cable, which measurements are transmitted to and stored in a logging device. At least one of the first and second intrinsic measuring units can be an eddy current measurement device to measure deflection of at least one of the first and second resilient members using eddy currents.

Methods for sensing formation properties while drilling a well are described. An antenna system and transceiver electronics system are disposed on a drill collar segment. The antenna system includes at least one transmitter antenna for creating an electromagnetic field and at least one receiver antenna for detecting the electromagnetic field. At least one antenna in the antenna system is a magnetic dipole based antenna having at least two slot based magnetic dipoles. The slot based magnetic dipoles include slots in an outer surface of the drill collar segment, wire holes beneath the outer surface connecting the slots with each other and with the transceiver electronics system, a ferrite rod placed in each slot, and, at least one continuous antenna wire passing through the slots and the wire holes.

Methods for sensing formation properties while drilling a well are described. An antenna system and transceiver electronics system are disposed on a drill collar segment. The antenna system includes at least one transmitter antenna for creating an electromagnetic field and at least one receiver antenna for detecting the electromagnetic field. At least one antenna in the antenna system is a magnetic dipole based antenna having at least two slot based magnetic dipoles. The slot based magnetic dipoles include slots in an outer surface of the drill collar segment, wire holes beneath the outer surface connecting the slots with each other and with the transceiver electronics system, a ferrite rod placed in each slot, and, at least one continuous antenna wire passing through the slots and the wire holes.

Among the methods provided is a method comprising: providing a fracturing fluid that comprises a base fluid and an additive having a high dielectric constant; and introducing the fracturing fluid into least a portion of a subterranean formation.

Among the methods provided is a method comprising: providing a fracturing fluid that comprises a base fluid and an additive having a high dielectric constant; and introducing the fracturing fluid into least a portion of a subterranean formation.

Properties of a geological formation, such as dielectric constant and conductivity, may be determined by a propagation well log data acquired by a propagation well logging tool based at least in part on a relative longitudinal position of two or more receivers of the propagation well logging tool. In some embodiments, the relative longitudinal position of the at least two receivers is based at least in part on a first distance between a first receiver of the at least two receivers and a transmitter of the propagation well logging tool and a second distance between a second receiver of the at least two receivers and the transmitter.

A method for obtaining full tensor gain compensated propagation measurements includes processing a full tensor voltage measurement to obtain a fully gain compensated tensor quantity. An electromagnetic logging tool including at least first and second axially spaced transmitters and at least first and second axially spaced receivers is rotated in a subterranean borehole. A plurality of voltage measurements are acquired while rotating to obtain a full tensor voltage measurement which is in turn processed to obtain the fully gain compensated tensor quantity.

A method for obtaining full tensor gain compensated propagation measurements includes processing a full tensor voltage measurement to obtain a fully gain compensated tensor quantity. An electromagnetic logging tool including at least first and second axially spaced transmitters and at least first and second axially spaced receivers is rotated in a subterranean borehole. A plurality of voltage measurements are acquired while rotating to obtain a full tensor voltage measurement which is in turn processed to obtain the fully gain compensated tensor quantity.

A system includes a drillstring with an electromagnetic (EM) transmitter in a first borehole. The system also includes at least one fiber optic sensor deployed in a second borehole. The system also includes a processor configured to determine a distance or direction of the EM transmitter relative to the at least one fiber optic sensor based on EM field measurements collected by the at least one fiber optic sensor in response to an EM field emitted by the EM transmitter.

A system includes a drillstring with an electromagnetic (EM) transmitter in a first borehole. The system also includes at least one fiber optic sensor deployed in a second borehole. The system also includes a processor configured to determine a distance or direction of the EM transmitter relative to the at least one fiber optic sensor based on EM field measurements collected by the at least one fiber optic sensor in response to an EM field emitted by the EM transmitter.