Abstract: Direct field cancelation with optional receive antenna compensation is provided in at least some gradient induction logging tool embodiments. Illustrative embodiments include a spatial gradient antenna arrangement having multiple spatially-separated multi-component coil antennas and a multi-component coil antenna having bucking coils that cancel the effects of both the direct field and the gradient of the direct field on the receive signal. Other tool embodiments include a multi-component coil antenna and a spatial gradient antenna arrangement having spatially separated multi-component coil antennas with bucking coils that cancel the effects of both the direct field and the gradient of the direct field on the receive signal. Those embodiments employing a spatial gradient antenna arrangement for receiving may further be configured to provide compensated measurements by combining measurements from rotated orientations of the spatial gradient antenna.

Abstract: Methods and systems are included that relate to the detection and monitoring of defects in wellbore conduits using a distributed sensor system and a wireline transmitter. A method for inspection of wellbore conduits may comprise: running a wireline transmitter into a wellbore; generating an electromagnetic field using the wireline transmitter, wherein the electromagnetic field penetrates one or more conduits disposed in the wellbore, and wherein the electromagnetic field induces emission of at least one secondary electromagnetic field from the one or more conduits; generating at least one signal in response to the secondary electromagnetic field, wherein the at least one signal is generated using a distributed sensor system, and wherein the distributed sensor system comprises electromagnetic field sensors installed in the wellbore and distributed along the one or more conduits; and identifying a pipe electromagnetic or geometric property of the one or more conduits based on the at least one signal.

Abstract: A system and method according to which a downhole component positioned behind a casing is powered, the casing extending within an oil and gas wellbore that traverses a subterranean formation. Powering the downhole component may include inducing an electrical current to flow in the casing; permitting the electrical current to flow out of the casing to create a first potential difference between a first point and a second point spaced therefrom, the first and second points being located behind the casing; utilizing the first potential difference to store electrical power; and supplying the stored electrical power to the downhole component positioned behind the casing to thereby power the downhole component. The system may include a power source in electrical communication with the casing; a power harvester positioned behind the casing and in electrical communication with the downhole component; and a current return unit in electrical communication with the power source.

Abstract: A method of monitoring electromagnetic properties of a subsurface formation may include: obtaining a resistivity distribution in the subsurface formation; identifying sensor positions along a borehole; determining an effective resistivity of each region around a sensor position; deriving from the effective resistivities of regions associated with each sensor position an optimum resonance frequency; tuning an array of sensors to provide each sensor with the optimum resonance frequency; deploying the sensor array in the borehole; and collecting electromagnetic field measurements. Each sensor may include: a coil antenna positioned in a subsurface formation having a resistivity, the coil antenna generating a induced voltage signal from an electromagnetic field in the subsurface formation; and a resonant modulation circuit that converts the induced voltage signal into a telemetry signal, the resonant modulation circuit having a resonance frequency optimized for said formation resistivity.

Abstract: A downhole tool including a transmitter coil assembly and a receiver coil assembly. The coil assembly includes at least one first coil having a first support member with a first single layer of wire wound therearound. The coil assembly further includes at least one second coil. The second coil includes a second support member having a second single layer of wire wound therearound. The first support member is disposed within the second support member, and the first single layer spaced apart from the second single wire by a distance of D.

Abstract: Improved algorithm for estimating anisotropic formation resistivity profile using a multi-component induction tool are disclosed. A method for estimating anisotropic formation resistivity profile of a formation comprises obtaining borehole corrected log data and determining at an azimuth angle of the formation. One or more formation bed boundaries are located and initial formation properties are calculated. One of a plurality of inversion windows is sequentially selected and a one-dimensional inversion of each of the sequentially selected one of the plurality of inversion windows is performed.

Abstract: Fast-changing dip formation resistivity estimation methods and systems, including a formation resistivity estimation method that includes estimating an initial horizontal resistivity based upon acquired formation logging data and determining an initial value set of one or more value sets. The method further includes determining each additional value set of the one or more value sets using a 1-dimensional inversion initialized with a previously determined value set of the one or more value sets, and displaying a final value set of the one or more value sets. Each of the 1-dimensional inversions is performed using a cross-bedded formation model, and each of the one or more value sets includes one or more parameters selected from the group consisting of a horizontal resistivity, a vertical resistivity, a formation dip angle, a formation azimuth angle, a tool inclination angle, a tool azimuth angle and a depth.

Abstract: Device, system, and method embodiments provide fluid front monitoring via permanent, casing-mounted electromagnetic (EM) transducers. One or more casing strings have one or more transmit antennas that each encircle a casing string and one or more receive antennas that similarly encircle the casing string, with at least one receive antenna oriented differently from at least one transmit antenna to provide sensitivity to at least one cross-component signal. A processor unit derives an estimated distance to a fluid front, and may further determine a direction and orientation of the fluid front for display to a user. Signals from an array of transmit and receive antennas may be combined, optionally with signals from other boreholes, to locate and track multiple points on the fluid front. In response to the determined location and progress of the front, the processor unit may further provide control settings to adjust injection and/or production rates.

Abstract: Calibration tools and procedures that provide one or more calibration methods for multi-component induction tools can include use of a tilted elliptical loop and a circular loop. Measurement signals may be used for analytic calibration of a multicomponent induction tool. Additional apparatus, systems, and methods are disclosed.

Abstract: Various resistivity logging tools, systems, and methods are disclosed. At least some system embodiments include a logging tool and at least one processor. The logging tool provides transmitter-receiver coupling measurements that include at least direct coupling along the longitudinal tool axis (Czz), direct coupling along the perpendicular axis (Cxx or Cyy), and cross coupling along the longitudinal and perpendicular axes (Cxz, Cyz, Czx, or Czy). The processor combines a plurality of the coupling measurements to obtain inversion parameters. Based at least in part on the inversion parameter, the processor performs an inversion process to determine a vertical conductivity and, based in part on the vertical conductivity, determines borehole corrected values for said transmitter-receiver coupling measurements. One or more of the borehole corrected values can be provided as a function of borehole position.

Abstract: Illustrative logging methods, systems, and software, provide for correction of cross-coupling error via a complex-plane extrapolation technique. Frequency-dependent measurements at each given borehole position will trace out a dependence of a quadrature signal component on the in-phase component. With linear or curve-fit extrapolation to the real axis, the cross-coupling error is readily compensated, enabling more accurate formation property logs to be derived over greater range of operating environments. The technique is particularly suitable for use with laterolog resistivity tools, where cross-coupling between current and voltage conductors might otherwise be problematic.

Abstract: A system and method according to which a downhole component positioned behind a casing is powered, the casing extending within an oil and gas wellbore that traverses a subterranean formation. Powering the downhole component may include inducing an electrical current to flow in the casing; permitting the electrical current to flow out of the casing to create a first potential difference between a first point and a second point spaced therefrom, the first and second points being located behind the casing; utilizing the first potential difference to store electrical power; and supplying the stored electrical power to the downhole component positioned behind the casing to thereby power the downhole component. The system may include a power source in electrical communication with the casing; a power harvester positioned behind the casing and in electrical communication with the downhole component; and a current return unit in electrical communication with the power source.

Abstract: Various embodiments include apparatus and methods to provide a skin-effect correction. The skin-effect correction can be based on a pre-calculated correction coefficient library. In various embodiments, a skin-effect correction procedure can be applied that only uses a single-frequency R-signal measurement. In addition, an embodiment of a skin-effect correction procedure using a single-frequency R-signal measurement can be applied whenever the quality of the data from one of the multiple frequencies normally used in a multi-frequency method is reliable. Additional apparatus, systems, and methods are disclosed.

Abstract: A system and method for improving the accuracy of galvanic tool measurements is described. The system (300) may include a survey electrode (A0) and a first monitor electrode (M1?) positioned above the survey electrode. A second monitor electrode (M1) may be positioned below the survey electrode, and a first conductive wire (307) may couple the first monitor electrode to the second monitor electrode. A first measurement point (302) may be located on the conductive wire, and a first resistive element (Rm1) may be coupled to the conductive wire.

Abstract: Formation properties may be more efficiently derived from measurements of multi-frequency, multi-component array induction tools, by emphasizing the measurements associated with shorter spacings/lower frequencies in certain regions and short-to-middle spacings/higher frequencies in other regions. In at least one embodiment, a disclosed logging system includes a logging tool that when conveyed along a borehole through a formation obtains multi-component transmit-receive antenna coupling measurements with multiple arrays having different antenna spacings; and a processing system that operates on the measurements. The processing system derives from said measurements one or more formation parameter estimates; determines measurement weight coefficients for a cost function based on said one or more formation parameter estimates; and inverts said measurements with said cost function to obtain one or more enhanced parameter estimates.

Abstract: Tools, systems, and methods are disclosed for multi-component induction logging with iterative analytical conversion of tool measurements to formation parameters. At least some system embodiments include a logging tool and at least one processor. The logging tool provides transmitter-receiver coupling measurements that include at least diagonal coupling measurements (Hzz, Hxx, and/or Hyy) and cross-coupling measurements (Hxy, Hxz, and Hyz). The processor employs an iterative analytical conversion of the cross-coupling measurements into formation resistive anisotropy and dip information. The processor may further provide one or more logs of the resistive anisotropy and/or dip information.

Abstract: A method and system according to which electrical communication is established between a primary circuit positioned inside a downhole tubular and a secondary circuit positioned outside the downhole tubular. In an exemplary embodiment, the method includes positioning the secondary circuit outside the downhole tubular, the secondary circuit including a magnetically permeable secondary core and a secondary winding extending proximate the secondary core; positioning a primary circuit inside the downhole tubular, the primary circuit including a magnetically permeable primary core and a primary winding extending proximate the primary core; and supplying electrical power and/or data to the primary winding with an electrical source so that a magnetic flux is channeled through the primary and secondary cores to induce an electromotive force in the secondary winding, thus establishing electrical communication between the primary and secondary circuits to transfer power and/or data therebetween.

Abstract: Methods and systems are included that relate to the detection and monitoring of defects in wellbore conduits using a distributed sensor system and a wireline transmitter. A method for inspection of wellbore conduits may comprise: running a wireline transmitter into a wellbore; generating an electromagnetic field using the wireline transmitter, wherein the electromagnetic field penetrates one or more conduits disposed in the wellbore, and wherein the electromagnetic field induces emission of at least one secondary electromagnetic field from the one or more conduits; generating at least one signal in response to the secondary electromagnetic field, wherein the at least one signal is generated using a distributed sensor system, and wherein the distributed sensor system comprises electromagnetic field sensors installed in the wellbore and distributed along the one or more conduits; and identifying a pipe electromagnetic or geometric property of the one or more conduits based on the at least one signal.

Abstract: A resistivity logging tool includes a plurality of excitation electrodes, at least one return electrode, and a plurality of monitor electrodes. The resistivity logging tool also includes a controller that determines a set of independent currents to be emitted by at least some of the plurality of excitation electrodes during an excitation cycle based on at least one measured downhole parameter and at least one predetermined constraint.

Abstract: A method and apparatus according to which electrical communication is established between a primary circuit positioned inside a downhole tubular and a secondary circuit positioned outside the downhole tubular. In an exemplary embodiment, the method includes positioning the secondary circuit outside the downhole tubular, the secondary circuit including a magnetically permeable secondary core and a secondary winding extending proximate the secondary core; positioning a primary circuit inside the downhole tubular, the primary circuit including a magnetically permeable primary core and a primary winding extending proximate the primary core; and supplying electrical power and/or data to the primary winding with an electrical source so that a magnetic flux is channeled through the primary and secondary cores to induce an electromotive force in the secondary winding, thus establishing electrical communication between the primary and secondary circuits to transfer power and/or data therebetween.