Abstract: Systems, methods, and software for determining a thickness of a well casing are described. In some aspects, the thickness of the well casing is determined based on results of comparing a measured waveform and model waveforms. The measured waveform and model waveforms are generated based on operating an acoustic transmitter and an acoustic receiver within a wellbore comprising the well casing.

Abstract: Systems, methods, and software for determining impedance of a casing-cement bond are described. In some aspects, the bond impedance is determined based on results of comparing a measured waveform and a model waveform. The model waveform corresponds to an estimated impedance of the bond and corresponds to a ray tracing of an acoustic signal that accounts for a radiation pattern of the acoustic transmitter and a curvature of the well casing. The measured waveform and the model waveform are generated based on operating an acoustic transmitter and an acoustic receiver within a wellbore comprising the well casing.

Abstract: An example apparatus for downhole cement inspection may include a tool body and an acoustic transmitter coupled to the tool body. An acoustic receiver may be coupled to the tool body at a first distance from the acoustic transmitter. A first array of acoustic receivers may be coupled to and positioned around a circumference of the tool body at a second distance from the acoustic transmitter. The second distance may be greater than the first distance. The acoustic receiver may be one receiver of a second array of acoustic receivers coupled to and positioned around the circumference of the tool body at the first distance. The first distance may be approximately three feet and the second distance may be approximately five feet.

Abstract: A method for logging a wellbore includes positioning a downhole tool having a downhole clock in the wellbore, logging the wellbore with the downhole tool, transmitting a surface signal from a wellbore surface to the downhole tool, and receiving the surface signal at the downhole tool. The method also includes transmitting a downhole signal from the downhole tool to the surface, receiving the downhole signal at the wellbore surface, and determining clock drift based on an arrival time of the surface signal at the downhole tool and an arrival time of the downhole signal at the wellbore surface.

Abstract: A method that includes obtaining log data of a downhole formation, and characterizing the downhole formation by determining stiffness coefficients including C33, C44, C66, C11, C12, and C13. C13 is a function of C33, C44, C66, and at least one of a kerogen volume and a clay volume derived from the log data. In another method or system, C13 is derived based at least in part on C11 calculated as C11=k1[C33+2(C66?C44)]+k2 or C33 calculated as C33=((C11?k2)/k1)?2(C66?C44), where k1 and k2 are predetermined constants. In another method or system, C13 is derived in part from at least one of a kerogen volume derived from the log data, a clay volume derived from the log data, C11 calculated as C11=k1[C33+2(C66?C44)]+k2, or C33 calculated as C33=((C11?k2)/k1)?2(C66?C44), where k1 and k2 are predetermined constants.

Abstract: An example apparatus for downhole cement inspection may include a tool body and an acoustic transmitter coupled to the tool body. An acoustic receiver may be coupled to the tool body at a first distance from the acoustic transmitter. A first array of acoustic receivers may be coupled to and positioned around a circumference of the tool body at a second distance from the acoustic transmitter. The second distance may be greater than the first distance. The acoustic receiver may be one receiver of a second array of acoustic receivers coupled to and positioned around the circumference of the tool body at the first distance. The first distance may be approximately three feet and the second distance may be approximately five feet.

Abstract: Systems, methods, and software for determining properties of a medium surrounding an exterior portion of a well casing are described. In some aspects, the properties of the medium are determined based on measurements of detected acoustic energy and distances between one or more acoustic transmitters and two or more acoustic receivers. The measurements are obtained based on operating the transmitters and the receivers within a wellbore that includes the well casing.

Abstract: Systems, methods, and software for determining impedance of a casing-cement bond are described. In some aspects, the bond impedance is determined based on results of comparing a measured waveform and a model waveform. The model waveform corresponds to an estimated impedance of the bond and corresponds to a ray tracing of an acoustic signal that accounts for a radiation pattern of the acoustic transmitter and a curvature of the well casing. The measured waveform and the model waveform are generated based on operating an acoustic transmitter and an acoustic receiver within a wellbore comprising the well casing.

Abstract: Systems, methods, and software for determining a thickness of a well casing are described. In some aspects, the thickness of the well casing is determined based on results of comparing a measured waveform and model waveforms. The measured waveform and model waveforms are generated based on operating an acoustic transmitter and an acoustic receiver within a wellbore comprising the well casing.

Abstract: A method that includes obtaining log data of a downhole formation, and characterizing the downhole formation by determining stiffness coefficients including C33, C44, C66, C11, C12, and C13. C13 is a function of C33, C44, C66, and at least one of a kerogen volume and a clay volume derived from the log data. In another method or system, C13 is derived based at least in part on C11 calculated as C11=k1[C33+2(C66?C44)]+k2 or C33 calculated as C33=((C11?k2)/k1)?2(C66?C44), where k1 and k2 are predetermined constants. In another method or system, C13 is derived in part from at least one of a kerogen volume derived from the log data, a clay volume derived from the log data, C11 calculated as C11=k1[C33+2(C66?C44)]+k2, or C33 calculated as C33=((C11?k2)/k1)?2(C66?C44), where k1 and k2 are predetermined constants.

Abstract: Systems, methods, and software for determining properties of a medium surrounding an exterior portion of a well casing are described. In some aspects, the properties of the medium are determined based on measurements of detected acoustic energy and distances between one or more acoustic transmitters and two or more acoustic receivers. The measurements are obtained based on operating the transmitters and the receivers within a wellbore that includes the well casing.

Abstract: Systems, methods, and software for determining a thickness of a well casing are described. In some aspects, the thickness of the well casing is determined based on results of comparing a measured waveform and model waveforms. The measured waveform and model waveforms are generated based on operating an acoustic transmitter and an acoustic receiver within a wellbore comprising the well casing.

Abstract: A system and method for determining shear wave anisotropy in a vertically transversely isotropic formation is disclosed. The method includes generating a broad band Stoneley wave and a broad band dipole flexural wave. The broad band Stoneley wave and a broad band dipole flexural wave may be generated at a logging tool located within a wellbore. The method also includes receiving at the logging tool first data corresponding to the broad band Stoneley wave and second data corresponding to the broad band dipole flexural wave. The method also includes determining a vertical shear wave constant, c66, by at least applying an inversion algorithm to the first data and the second data.

Abstract: A method for estimating porosity of an earth formation from measurements of acoustic energy traversing the earth formation and from measurements of seismoelectric voltages generated in the formation in response to the acoustic energy. The method includes the steps of measuring the acoustic energy traversing the earth formation and measuring said seismoelectric voltages generated in response to the acoustic energy traversing the formation. A seismoelectric signal is synthesized from the measurements of the acoustic energy using an initial value of the porosity. A difference is determined between the synthesized seismoelectric voltages and the measured seismoelectric voltages. The initial value of porosity is adjusted, and the steps of synthesizing the seismoelectric voltages from the acoustic signal, determining the difference, and adjusting the value of porosity are repeated until the difference drops below a predetermined threshold or the difference reaches a minimum value.