Abstract: A method and apparatus for identifying a ballooning zone in downhole formations. In one embodiment, a method for identifying a ballooning zone in downhole formations includes disposing a drill string in a wellbore. The drill string includes a plurality of wired drill pipes connected end-to-end, and a bottomhole assembly connected to the drill pipes. While circulating drilling fluid through the wellbore, a first resistivity of a formation drilled is measured. While not circulating drilling fluid through the wellbore, a second resistivity of the formation drilled is measured. The first resistivity and the second resistivity are compared. Based on a result of the comparing, a level of ballooning attributable to the formations is identified.

Abstract: An electromagnetic measurement system and related methods are provided. The system includes an electromagnetic source located at a predetermined depth and configured to generate electromagnetic waves in surrounding formations, and a grid of electromagnetic detectors located on a surface of the rock formation and configured to detect the electromagnetic waves generated by the electromagnetic source and reflected by an underground hydrocarbons reservoir. The system also includes a data processing unit configured to process first data and second data related to the electromagnetic waves detected by the grid of electromagnetic detectors, to extract changes of the underground hydrocarbon reservoir, the first data and the second data each being acquired for up to one week, at least two months apart from one another. The electromagnetic source and the grid of electromagnetic detectors are not moved or removed between when the first data was acquired and when the second data was acquired.

Abstract: A method of processing data includes: disposing a downhole tool in a borehole in an earth formation, the downhole tool including a conductive carrier, a transmitter, a first receiver disposed at a first axial distance from the transmitter, and a second receiver disposed at a second axial distance from the transmitter that is less than the first axial distance; performing a downhole electromagnetic operation, the operation including transmitting an electromagnetic (EM) signal from the transmitter into the formation and detecting a first EM response signal by the first receiver and a second EM response signal by the second receiver; applying a linear transformation to the second EM response signal to generate a transformed signal, the linear transformation having parameters associated with a set of data corresponding to a signal representing the conductive carrier; and subtracting the transformed signal from the first EM response signal to generate a corrected EM signal.

Abstract: An apparatus and method for a property ahead of a drill bit in a borehole penetrating a formation. The apparatus may include at least one receiver toroid disposed on a carrier and a transmitter toroid configured to induce an electromagnetic signal in the formation and disposed between the drill bit and the at least one receiver toroid. The apparatus may include at least one processor configured to estimate the property using a signal produced by the at least one receiver. The method may include estimating the property using the signal produced by the at least one receiver toroid. The method may also include one or more of: (i) generating a conductivity curve based on signals from at least one receiver toroid, (ii) validating signals from one receiver toroid based on a conductivity curve of another receiver toroid, and (iii) filtering a receiver toroid signal using lateral resistivity information.

Abstract: A method to determine one or more borehole corrected formation properties using measurements made using a logging tool disposed in a borehole penetrating an earth formation is disclosed. The measurements are used to determine an apparent conductivity tensor for the formation and, for a set of parameters, a parameter value for each parameter in a subset of the set of parameters. A parameter value for each parameter in the set of parameters not in the subset is provided and a borehole-inclusive modeled conductivity tensor is computed. The apparent conductivity tensor and the borehole-inclusive modeled conductivity tensor are iteratively used to optimize the parameter values, and the optimized parameter values are used to compute an optimized conductivity tensor. A borehole corrected conductivity tensor is computed using the optimized conductivity tensor, and the borehole corrected formation properties are determined using the borehole corrected conductivity tensor and/or the optimized parameter values.

Abstract: To analyze content of a subterranean structure, electric field measurements at plural source-receiver azimuths in a predefined range are received. Total magnetic field measurements are also received at plural source-receiver azimuths in the predefined range. The electric field measurements and the total magnetic field measurements are provided to an analysis module to enable determination of electrical resistivity anisotropy of the subterranean structure.

Abstract: Certain embodiments described herein provide an estimate of the magnetic interference incident upon a drilling system using multiple magnetic sensors within a downhole portion of the drilling system in a first wellbore. Certain embodiments utilize the magnetic measurements to determine an axial interference resulting from one or more magnetic portions of the downhole portion and to provide an estimate of a relative location of a second wellbore spaced from the first wellbore.

Abstract: A system determines a volumetric fraction of oil in a formation penetrated by a borehole, the formation comprising an unconventional reservoir. The system includes a carrier configured to be conveyed through the borehole and a geochemical tool disposed at the carrier and configured to determine a mineral makeup of the formation and excess carbon not apportioned to any mineral of the mineral makeup, the excess carbon being associated with kerogen and oil in the formation. An NMR tool disposed at the carrier determines porosity of fluid in the formation, the fluid excluding the kerogen in the formation. A density tool disposed at the carrier determines bulk density of the formation, and a processor determines the volumetric fraction of oil in the formation based on the excess carbon, the porosity of the fluid in the formation, and the bulk density of formation.

Abstract: Logging systems and methods to provide azimuthally-sensitive saturation logs. In some embodiments a processor operates on formation porosity and resistivity measurements from an azimuthally-sensitive logging tool assembly to derive a saturation log having a dependence on tool position and rotation angle, and possibly on radial distance as well. The processor may provide the log to a user via a screen, printer, or some other display mechanism. The logging tool assembly includes at least one tool to measure formation porosity. Suitable tools include a gamma density tool, a neutron density tool, a nuclear magnetic resonance tool, and an acoustic tool. The tool assembly further includes at least one tool to measure formation resistivity. Suitable tools include a laterolog tool, an induction tool, and a propagation resistivity tool. The tool assembly can be a wireline sonde, a tubing-conveyed logging assembly, or a logging while drilling tool assembly.

Abstract: A computer system and a computer-implemented method for calibrating a reservoir characteristic including a permeability of a rock formation. The method includes inputting a measured product KH of a measured permeability K and a flowing zone thickness H over a plurality of corresponding zones in one or more wells and inputting porosity logs for each measured product KH in each of the plurality of zones obtained from the one or more wells. The method further includes reading a porosity-permeability cloud of data points; calculating, for each zone, a predicted product KH from the porosity log using the porosity-permeability cloud of data points; determining one or more weighting coefficients between the predicted KH and the measured KH corresponding to each zone; and calibrating the measured permeability corresponding to each zone using the one or more weighting coefficients.

Abstract: A method of passive surveying comprises generating one or more detected signals by passively detecting a signal generated within a subsurface earth formation due to a seismoelectric response or an electroseismic response in at least one porous subsurface earth formation containing at least one fluid, and processing the one or more detected signals to determine at least one property of the subsurface earth formation.

Abstract: A method of passive surveying comprises generating one or more detected signals by passively detecting a signal generated within a subsurface earth formation due to a seismoelectric response or an electroseismic response in at least one porous subsurface earth formation containing at least one fluid, and processing the one or more detected signals to determine at least one property of the subsurface earth formation.

Abstract: Locating and/or marking equipment, such as a locate transmitter or locate receiver, a marking device, or a combined locate and marking device, may be communicatively coupled to and/or equipped with a mobile/portable device (e.g., a mobile phone, personal digital assistant or other portable computing device) that provides processing, electronic storage, electronic display, user interface, communication facilities and/or other functionality (e.g., GPS-enabled functionality) for the equipment. A mobile/portable device may be mechanically and/or electronically coupled to the equipment, and may be programmed so as to log and generate electronic records of various information germane to a locate and/or marking operation (e.g., locate information, marking information, and/or landmark information). Such records may be formatted in various manners, processed and/or analyzed on the mobile/portable device, and/or transmitted to another device (e.g., a remote computer/server) for storage, processing and/or analysis.

Abstract: Electrical property contrast difference maps of the subsurface formations may be produced using surface and/or near surface array of transmitters and receivers tuned to emit and receive electromagnetic (EM) signals. The electrical property may be resistivity or conductivity. The maps may be time based. A time based trend change may be used to predict the location and movement of fluids within the hydrocarbon bearing or any other subsurface zones where resistivity and/or conductivity values of the fluids within these zones change over time.

Abstract: Methods and apparatus to process measurements associated with drilling operations are described. An example method of modifying processing results during a subterranean formation drilling operation includes identifying a plurality of parameters and processing measurements associated with the subterranean formation obtained while drilling and the plurality of parameters to generate first results. Additionally, the example method includes processing measurements associated with the subterranean formation obtained while drilling is temporarily suspended and the plurality of parameters to generate second results and comparing the first and second results. Further, the example method includes, in response to the comparison of the first and second results, modifying the first results based on the second results to improve a quality of the first results.

Abstract: A method for determining mobile water saturation in a reservoir having a borehole extending through the reservoir is disclosed. The method involves obtaining a first borehole data log while the reservoir is subjected to first fluid conditions, and causing a mobile water displacement in the reservoir by changing the fluid conditions in the borehole to cause the reservoir to be subjected to second fluid conditions, the second fluid conditions differing from the first fluid conditions. The method further involves obtaining a second borehole data log under the second fluid conditions, and estimating the mobile water displacement using the first and second data logs, the estimated mobile water displacement providing an estimate of the mobile water saturation in the reservoir.

Abstract: A method for assigning a wettability or related parameter to a subvolume of formation located between two or more boreholes is described. The method includes the steps of obtaining measurements of resistivity at a subvolume, obtaining further parameters determining a relation between resistivity and saturation from logging measurements along the two or more boreholes, obtaining geological measurements defining geological or rock-type boundaries within the formation between the two or more boreholes, selecting the subvolume such that it is intersected by the geological or rock-type boundaries; transforming the resistivity measurements into the saturation at the subvolume; and using the saturation and/or the further parameters to determine the wettability or related parameter for the subvolume.

Abstract: Method for rapid inversion of data from a controlled-source electromagnetic survey of a subterranean region. Selected (51) common-receiver or common-source gathers of the data are reformed into composite gathers (52) by summing their data. Each composite gather is forward modeled (in the inversion process) with multiple active source locations (53). Computer time is reduced in proportion to the ratio of the total number of composite gathers to the total number of original common-receiver or common-source gathers. The data may be phase encoded to prevent data cancellation. Methods for mitigating loss of far offset information by data overlap in the summing process are disclosed.

Abstract: A technique provides a methodology for improving surveys of subterranean regions. The methodology comprises estimating macro anisotropy and an intrinsic or micro anisotropy of an overburden. A surface electromagnetic survey is conducted, and the data from the survey is inverted based on or including information gained from estimating the macro anisotropy and/or intrinsic anisotropy. A processor system can be used to conduct the inversion with the adjustments for anisotropy to improve the information provided by the survey.

Abstract: An apparatus and method for estimating a parameter of interest in a borehole penetrating an earth formation using a receiver and a transmitter, both disposed on a carrier, with aligned magnetic moments to correct for bending of carrier during borehole investigations. The apparatus may include a transmitter with at least two substantially perpendicular coils and a receiver with at least one coil oriented with at least one or the transmitter coils. The method may include aligning the magnetic moment of the transmitter and the magnetic moment of the receiver prior to estimating the parameter of interest. The method may include supplying a constant electric current to one of the transmitter coils while supplying a varying electric current to another of the transmitter coils. The method may include estimating a direction of bending or angle of bending of the carrier.

Abstract: In some embodiments, an apparatus and a system, as well as a method and an article, may operate to receive down hole tool environmental temperature data, axial temperature data, radial temperature data, and log data. Further activity may include applying temperature effects compensation associated with the environmental temperature data and the down hole log data using a fitting function model obtained from a trained neural network to transform the down hole log data into corrected log data. Additional apparatus, systems, and methods are described.

Abstract: Methods and systems for processing acoustic measurements related to subterranean formations. The methods and systems provide receiving acoustic waveforms with a plurality of receivers, deriving slowness of the formation based on the acoustic waveforms, and modeling dominant waveforms in the acoustic waveforms based on the formation slowness, wherein deriving the formation slowness comprises parametric inversion for complex and frequency dependent slowness and the derived complex slowness has real and imaginary parts.

Abstract: A method to obtain gain-corrected measurements. A measurement tool having one or more arrays is provided, wherein the arrays include two co-located triaxial transmitters and two co-located triaxial receivers. Measurements are obtained using the transmitters and the receivers. Impedance matrices are formed from the obtained measurements and the impedance matrices are combined to provide gain-corrected measurements. The apparatus may alternatively be a while-drilling logging tool having one or more arrays, wherein each array comprises a transmitter, a receiver, and a buck, and wherein the signal received by the receiver is subtracted from the signal received by the buck or vice versa. A slotted shield may be incorporated into either embodiment of the tool. The slots may form one or more island elements. A material is disposed in the slots. The islands and shield body have complementary tapered sides that confine the islands within the shield body.

Abstract: A method of passive surveying comprises generating one or more detected signals by passively detecting a signal generated within a subsurface earth formation due to a seismoelectric response or an electroseismic response in at least one porous subsurface earth formation containing at least one fluid, and processing the one or more detected signals to determine at least one property of the subsurface earth formation.

Abstract: Disclosed are various embodiments of a workflow or method for petrophysical rock typing of carbonates in an oil or gas reservoir or field comprising determining a Data Scenario (DS) for the reservoir or field, determining a plurality of Depositional Rock Types (DRTs) for the reservoir or field, determining a Digenetic Modification (DM) from a plurality of diagenetic modifiers or primary textures associated with the plurality of DRTs, selecting a Reservoir Type (RT) corresponding to the plurality of DRTs,determining at least one pore type, and determining, on the basis of the plurality of DRTs, the Diagenetic Modification (DM), and the at least one pore type, a plurality of Petrophysical Rock Types (PRTs) associated with the RT.

Abstract: A method for identifying drilling induced fractures while drilling a wellbore into a formation is disclosed. The method includes: obtaining multi-component induction data collected by a drill string including a multi-component induction tool; processing the data to estimate values for principal components; and identifying drilling induced fractures from the principal components. An instrument and a computer program product are disclosed.

Abstract: A method of passive surveying comprises generating one or more detected signals by passively detecting a signal generated within a subsurface earth formation due to a seismoelectric response or an electroseismic response in at least one porous subsurface earth formation containing at least one fluid, and processing the one or more detected signals to determine at least one property of the subsurface earth formation.

Abstract: A logging tool having a plurality of spatially separated antennas is provided and used to make propagation-style measurements in a formation. Tensors are formed using the propagation-style measurements and one or more quantities are computed using the tensors. A formation evaluation is performed using the computed quantities. The formation evaluation determines a formation property or parameter such as horizontal resistivity, vertical resistivity, relative dip, azimuthal dip, bed boundary location, or bed thickness. The computed quantities may include compensated phase shift resistivity, compensated attenuation resistivity, symmetrized phase shift resistivity, symmetrized attenuation resistivity, anti-symmetrized phase shift resistivity, and anti-symmetrized attenuation resistivity. The measurements may be corrected for antenna gain errors and an air calibration may be performed.

Abstract: A method of processing geophysical data including at least measured potential field data from a potential field survey of a surveyed region of the earth to provide a representation of the geology of said surveyed region, the method comprising generating a first model of said surveyed region by fitting data predicted by said first model to said measured data for a specified frequency range; predicting full range potential field data for all measured frequencies using said generated first model; comparing said full range predicted data to said measured potential field data to provide full range residual data representing a difference between the full range predicted data and the full range measured data, and interpreting said full range residual data to provide a representation of said geology of said surveyed region.

Abstract: A hydrocarbon exploration method is disclosed for generating anisotropic resistivity models of a subsurface reservoir from seismic and well data using a rock physics model. In one embodiment, the method comprises: selecting wells within a region of interest (101); obtaining a plurality of rock properties (102) and adjusting selected rock parameters (103) in the calibration of the rock physics model at the well locations; inverting porosity and shale content from seismic data (107); propagating the calibrated rock physics model to the region of interest (109) and calculating effective resistivity for the entire region of interest (109). The inventive method also provides for analyzing the uncertainty associated with the prediction of the resistivity volume.

Abstract: A method for processing well logging data includes method dividing the well logging data into a number of constant dimensional effect segments, where each constant dimensional effect segment defines an interval having a similar dimensional effect on the log response. The well logging data is taken from a highly deviated well. The method further includes dividing the constant dimensional effect segments into a number of constant property intervals, each constant dimensional effect segment including at least one corresponding constant property interval, and each constant property interval defining a wellbore distance over which a formation property is substantially constant that results in a log response having a low variance. The method further includes providing the constant property intervals to an output device.

Abstract: Disclosed are a production logging tool and method for evaluating fluid produced from a formation of an oilfield. The fluid is measured by a water sensor to determine if the fluid is water, and a chloride sensor to determine chloride levels of the fluid. Based on the chloride levels of the fluid, it can be determined whether the fluid is naturally occurring water, or if the fluid is an injection fluid.

Abstract: Determining parameters associated with a hydrocarbon bearing formation beneath a sea bed. At least some of the illustrative embodiments are methods including: obtaining data gathered regarding a plurality of distinct readings by sensors, the readings responsive to a source of electrical energy towed in water above the hydrocarbon bearing formation, the sensors sense an electrical parameter associated with the source; combining a first datum associated with a first path of travel of the source with a second datum associated with a second path of travel of the source, the second path of travel distinct from the first path of travel, and the combining creates a first combined datum; and determining the parameter associated with the hydrocarbon bearing formation by evaluating the first combined datum.

Abstract: Current supplied to electrical submersible pumps in wells is monitored, and signal processing based on wavelet analysis and phase diagram analysis is performed on the data obtained from monitoring. An incipient malfunction of the electrical submersible pump, such as one due to scale build-up in and around the pump, can be detected at an early stage.

Abstract: A method and system for producing look-ahead profiles measurements includes positioning an energy transmitter, such as a transmitting antenna, proximate to a borehole assembly tool. One or more energy receivers, such as receiving antennas, are positioned along a length of the borehole assembly. Next, energy is transmitted to produce look-ahead scans relative to the borehole assembly tool. Look-ahead graph data with an x-axis being a function of a time relative to the position of the borehole assembly tool is generated. The look-ahead graph is produced and displayed on a display device. The look-ahead graph may track estimated formation values based on earth models. The estimated formation values are displayed below a tool position history line that is part of the look-ahead graph. The estimated formation values in the look-ahead graph may be based on inversions of resistivity data from the look-ahead scans.

Abstract: Various embodiments include apparatus and methods of operation with respect to well logging. Apparatus and methods include a tool having an arrangement of transmitters and receivers that are operated at different positions downhole and a processing unit to process collected signals such that the arrangement of transmitters and receivers provides measurements that mimic operation of a different arrangement of transmitters and receivers. Additional apparatus, systems, and methods are disclosed.

Abstract: Methods and systems are provided for evaluating petrophysical properties of subterranean formations and comprehensively evaluating hydrate presence through a combination of computer-implemented log modeling and analysis. Certain embodiments include the steps of running a number of logging tools in a wellbore to obtain a variety of wellbore data and logs, and evaluating and modeling the log data to ascertain various petrophysical properties. Examples of suitable logging techniques that may be used in combination with the present invention include, but are not limited to, sonic logs, electrical resistivity logs, gamma ray logs, neutron porosity logs, density logs, NRM logs, or any combination or subset thereof.

Abstract: A method for drilling a wellbore proximate a salt structure includes measuring formation resistivity azimuthally. A map of spatial distribution of resistivity is determined from the azimuthal resistivity measurements. A distance from the wellbore to an edge of the salt structure is determined from the three dimensional volume map.

Abstract: Methods and related systems are described for analyzing electromagnetic survey data. Electromagnetic survey data of a subterranean formation is obtained using at least a downhole transceiver deployed in a borehole and a transceiver positioned on the surface or in another borehole. The electromagnetic survey data includes an incident wave component and a scattered wave component. The incident and scattered components are correlated so as to generate an image of the subterranean formation indicating spatial locations of one or more features, for example, electrical properties such as resistivity variations, in the formation. The image is based at least in part on one or more interference patterns of the incident and scattered wave components. The correlation preferably includes generating a simulation of the incident wave component propagated into the formation, and convolving the simulated propagated incident wave component with the scattered wave component.

Abstract: The present disclosure relates to a method to determine a characteristic of a subsurface formation using a downhole logging tool. A downhole logging tool having the ability to make substantially concurrent disparate measurements on the subsurface formation is provided and substantially concurrent disparate measurements on the formation using the downhole logging tool are made. Those measurements are used to solve a system of equations simultaneously and the solution to the system of equations is used to determine the characteristic of the subsurface formation.

Abstract: Various methods are disclosed, comprising obtaining a plurality of raw depth measurements for a wellbore; obtaining survey data about a bottom hole assembly; obtaining depth compensation information; calculating a plurality of compensated depth measurements from the raw depth measurements and the depth compensation information and one or more additional corrections for residual pipe compliance, tide, and rig heave; calculating sag angle and correcting the survey data with the sag angle; determining a high fidelity wellbore trajectory from the compensated depth measurements and the survey data; and then employing the high fidelity wellbore trajectory in various drilling, formation evaluation, and production and reservoir analysis applications. Depth compensation information may comprise at least one of weight on bit, a friction factor, temperature profile, borehole profile, drill string mechanical properties, hookload, and drilling fluid property. The surveys may include both static and continuous surveys.

Abstract: A method for determining orientation of an electrically conductive formation proximate an electrically substantially non-conductive formation includes measuring multiaxial electromagnetic induction response within the substantially non-conductive formation using an instrument disposed in a wellbore drilled through the formations. A difference from zero conductivity is determined for each component measurement of the multiaxial electromagnetic induction response. The differences are used to correct the measured response of each component measurement in the electrically conductive response. The corrected component measurements are used to determine the orientation of the conductive formation.

Abstract: Method for determining time-dependent changes [73] in the earth vertical and horizontal electrical resistivity and fluid saturations from offshore electromagnetic survey measurements. The method requires both online and offline data, which should include at least one electromagnetic field component sensitive at least predominantly to vertical resistivity and another component sensitive at least predominately to horizontal resistivity [62]. Using a horizontal electric dipole source, online Ez and offline Hz measurements are preferred. For a horizontal magnetic dipole source, online H2 and offline E2 data are preferred. Magnetotelluric data may be substituted for controlled source data sensitive at least predominantly to horizontal resistivity. Maxwell's equations are solved by forward modeling [64,65] or by inversion [66,67], using resistivity models of the subsurface that are either isotropic contrast, and [64,66] or anisotropic [65,67].

Abstract: The invention relates to a method and apparatus for determining the nature of a material in a cavity between one inner metal wall and one outer metal wall provided outside the inner metal wall. First a tool is located on the inside of the inner metal wall, where the tool comprises a pulse generator and a signal recorder. An electromagnetic short duration pulse is generated by means of the pulse generator, the pulse inducing mechanical vibrations in the walls. Data representing the reflections of the mechanical vibrations from said cavity is recorded by means of the signal recorder. The recorded data is analyzed to determine the nature of the material in the cavity.

Abstract: Apparatus for in-situ wellbore measurements, said apparatus comprising one or more sensors arranged outside a wellbore, one or more actuators associated with the sensors, an electromagnetic transceiver situated inside a non-magnetic portion of wellbore conduit and mounted on an electric-line logging cable, a downhole interface unit also located on the electric-line cable for controlling communication to the apparatus. Also a method of in-situ wellbore measurements using said apparatus.

Abstract: Various logging-while-drilling (LWD) systems and methods provide resistivity logging coupled with deep detection of elongated anomalies at acute angles, enabling effective geosteering without disrupting drilling operations and without requiring intervention in the operations of the existing well. One LWD system embodiment employs a tool having tilted antennas as the transmitter and the receiver, where at least one of the antennas is placed in the vicinity of the bit, making it possible to detect existing wells at distances of 50-100 feet. In some cases, the detection distance is increased by enhancing the visibility of the existing well using a contrast fluid treatment on target well, either to fill the bore or to surround the well with treated cement or fluids that invade the formation. At least one inversion method separates the inversion of formation parameters from the inversion of parameters specifying distance, direction, and orientation of the existing well.

Abstract: Certain embodiments described herein provide a measure of the misalignment of multiple acceleration sensors mounted in the downhole portion of a drill string. In certain embodiments, the measure of the misalignment corresponds to a measure of sag which can be used to provide an improved estimate of the inclination of the downhole portion of the drill string and/or the wellbore. Certain embodiments described herein provide an estimate of the magnetic interference incident upon a drilling system using multiple magnetic sensors mounted within a non-magnetic region of the downhole portion of the drilling system. Certain embodiments utilize the magnetic measurements to determine an axial interference resulting from one or more magnetic portions of the downhole portion and to provide an improved estimate of the azimuthal orientation of the downhole portion with respect to the magnetic field of the Earth.

Abstract: A method is provided for determining formation resistivity, anisotropy and dip from wellbore measurements includes moving a well logging instrument through subsurface formations. The instrument includes longitudinal magnetic dipoles and at least one of tilted and transverse magnetic dipoles. Formation layer boundaries and horizontal resistivities of the formation layers are determined from longitudinal magnetic dipole measurements. Vertical resistivities of the formation layers are determined by inversion of anisotropy sensitive measurements. Improved vertical resistivities of the formation layers and dips are determined by inverting symmetrized and anti-symmetrized measurements. Improved vertical resistivities, improved boundaries and improved dips are determined by inversion of the all dipole measurements. Improved horizontal resistivities, further improved layer boundaries and further improved dips are determined by inversion of all dipole measurements.

Abstract: A system and method for controlling a downhole portion of a drill string is provided. The method includes receiving signals from a first sensor package mounted at a first position to the downhole portion, the signals indicative of an orientation of the first sensor package. The method also includes receiving signals from a second sensor package mounted at a second position to the downhole portion, the signals indicative of an orientation of the second sensor package. The method further includes calculating a first amount of bend between the first and second sensor packages in response to the signals and transmitting control signals to an actuator which responds by adjusting the downhole portion to have a second amount of bend between the first and second sensor packages.

Abstract: The present disclosure relates to a method to determine a formation property of a subsurface formation. A downhole logging tool having two or more antennas, at least one of the antennas being a non-co-located triaxial antenna, is provided. Azimuthally sensitive measurements are obtained using the antennas of the downhole logging tool. The measurements are fitted to a Fourier series having Fourier coefficients and the non-co-location of the triaxial antenna is compensated for by adjusting the Fourier coefficients. Compensated measurements are determined using the adjusted Fourier coefficients and the formation property of the subsurface formation is determined using the compensated measurements. The compensating may use one or more scale factors that depend on an amplitude, phase, and/or frequency of the received signal, and an alignment angle between the triaxial antenna and another of the antennas of the logging tool.