Methods may include conveying a BHA comprising magnetic material in the borehole to a first borehole depth; using a magnetic sensor disposed on the BHA to produce a first magnetic measurement of a component of a magnetic field at the first borehole depth, the magnetic field including an axial component of the magnetic field oriented along a longitudinal axis of the BHA and a plurality of non-axial components unaligned with the axial component, wherein the magnetic field is affected by the magnetic material and wherein the first magnetic measurement is representative of at least one non-axial component of the plurality; estimating the axial component at the first borehole depth in dependence upon the first magnetic measurement; estimating an azimuth of the BHA at the first borehole depth using the axial component; and controlling drilling operations with the BHA in in dependence upon the azimuth.

A system for drilling a well may be adapted to process signals received from a fiber optic cable located in the casing of a previously drilled well or wells. The fiber optic cable may act as a distributed sensor receiving acoustic signals generated during the drilling of the well, and the system may be programmed to process the signals from the fiber optic cable to locate the borehole of the well being drilled, including its location relative to the previously drilled well or well. The system may be used to automatically update a well plan for the well being drilled responsive to information about the location of the borehole and also may be used to automatically adjust one or more drilling parameters or drilling operations responsive to the location of the second well borehole.

A deviated or horizontal wellbore is drilled in a geologic formation with a multiphase fluid including a gas by a rotating drill bit positioned at a downhole end of a drill string. Portions of the gas are released into the wellbore during the drilling. During the drilling, soundwaves are emitted into the geologic formation from within the wellbore by a set of acoustic emitters attached to the drill string. The received reflected soundwaves are transmitted by the set of solid acoustic couplers to a set of acoustic sensors contacting the solid acoustic couplers. The reflected soundwaves are received by the acoustic sensors. Rock properties of the geologic formation are determined based on the less attenuated reflected soundwaves transmitted to the acoustic sensors by the solid acoustic couplers. A drilling direction of the wellbore is adjusted based on the determined rock properties.

A method of obtaining position of a downhole tool with respect to a wellbore includes logging well data via the tool over a period of time and measuring a lateral acceleration of the tool over the period of time with one or more accelerometers embedded in the tool. The method further includes performing double integration on an acceleration of the tool over a period of time. The method also includes obtaining a displacement of the tool over the period of time from the double integration. The method also includes fitting the displacement of the tool over the period of time to a best fit curve. The method also includes subtracting the best fit curve from the displacement of the tool over the period of time.

System and methods of modeling casing deformation for hydraulic fracturing design are provided. A three-dimensional (3D) global model of a subsurface formation is generated. Values of material parameters for different points of the subsurface formation represented by the 3D global model are calculated based on a geomechanical analysis of well log data obtained for the subsurface formation. The calculated values are assigned to corresponding points of the global model. A 3D sub-model of a selected portion of the formation including a casing to be placed along a planned trajectory of a wellbore is generated based at least partly on the values assigned to the global model. Numerical damage models are applied to the global model and sub-model to simulate effects of a hydraulic fracturing treatment on the formation and casing along the planned wellbore trajectory. Casing deformation along the planned wellbore trajectory is estimated, based on the simulation.

Described is a system for estimating measured depth of a borehole. The system comprises a drilling fluid pulse telemetry system positioned in a borehole and processors connected with the drilling fluid pulse telemetry system. Time series measures are obtained from an environmental sensor package. Initial estimates of a time delay and path attenuation amplitude are determined. An error for the initial estimates is determined, and iterative minimization of the error is performed until source signal parameters converge, resulting in a least squares estimate of the source signal and the reflected signals. The least squares estimate is used to obtain time delay values, which are then used to continuously generate an estimate of a measured depth of the borehole.

A method for automatically selecting a frequency band for transmission of a mud pulse telemetry signal includes transforming acquired transducer measurements from a time domain to a frequency domain to obtain a spectrum of measurements. The spectrum of measurements is processed to compute a total energy in band and a standard deviation of the power spectral density in band for a plurality of frequency bands. A ratio of the total energy in band to the standard deviation acquiring a plurality of transducer measurements of transmitted mud pulse telemetry pressure pulses and of the power spectral density in band is computed for at least two of the plurality of frequency bands. The frequency band having the highest computed ratio is selected and automatically downlinked to a downhole mud pulse telemetry transmitter.

A well system includes a target wellbore that penetrates a subterranean formation and a relief wellbore drilled toward the target wellbore and a target intercept location where a fluid flows into the target wellbore from the subterranean formation. A bottom hole assembly is coupled to a drill string extended into the relief wellbore and includes a fiber optic ranging assembly having one or more fiber optic sensors positioned on a tubular member. The fiber optic sensors measure at least one of acoustic energy and thermal energy emitted by the fluid as it flows into the target wellbore. A computer system is communicably coupled to the one or more fiber optic sensors to process measurements of the fluid obtained by the one or more fiber optic sensors.

Measurements made by a near-bit magnetic sensor on a bottomhole assembly are used to determine the azimuth of the BHA. The sensor may be uncalibrated. The measurement may include a cross-axial component of the magnetic field. The method may include estimating the axial component of the near-bit magnetic field using the measurement. The method may include using the estimated azimuth of the BHA for controlling a direction of drilling. The method may include estimating the component Hxy. The method may include correcting the estimated axial component using an offset between a gravitational toolface and a magnetic toolface.

The present invention is essentially a portable seismic survey device and method using reflection seismology for mapping subterranean formations. The device includes an upper assembly, a firing pin operably associated with a firing pin actuator, a lower assembly including a cartridge holder capable of retaining a blasting cartridge, and a detonation sensor capable of detecting detonation of the blasting cartridge. The detonation sensor transmits a signal to an event marking device to trigger a recordation of detonation time and geographic location of the seismic survey device. A seismic wave is generated upon detonation which is then reflected back toward seismometers. Data from the event marking device and seismometers can then be processed to provide geological formation information.