A method that includes obtaining log data of a downhole formation, and characterizing the downhole formation by determining stiffness coefficients including C.sub.33, C.sub.44, C.sub.66, C.sub.11, C.sub.12, and C.sub.13. C.sub.13 is a function of C.sub.33, C.sub.44, C.sub.66, and at least one of a kerogen volume and a clay volume derived from the log data. In another method or system, C.sub.13 is derived based at least in part on C.sub.11 calculated as C.sub.11=k.sub.1[C.sub.33+2(C.sub.66−C.sub.44)]+k.sub.2 or C.sub.33 calculated as C.sub.33=((C.sub.11−k.sub.2)/k.sub.1)−2(C.sub.66−C.sub.44), where k.sub.1 and k.sub.2 are predetermined constants. In another method or system, C.sub.13 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, C.sub.11 calculated as C.sub.11=k.sub.1[C.sub.33+2(C.sub.66−C.sub.44)]+k.sub.2, or C.sub.33 calculated as C.sub.33=((C.sub.11−k.sub.2)/k.sub.1)−2(C.sub.66−C.sub.44), where k.sub.1 and k.sub.2 are predetermined constants.

Methods may include detecting the presence of a component in a wellbore including irradiating an interval of a wellbore containing one or more components of a wellbore tool with a neutron source, wherein the one or more components of the wellbore tool comprise one or more tracer materials; measuring the radiation emitted from the one or more components of a wellbore tool; determining one or more of presence, location, and intensity of the radiation emitted from the one or more components of the wellbore tool. Devices may include a first element comprising one or more tracer materials, wherein the one or more tracer materials emit gamma radiation upon irradiation with a neutron source; wherein the tool is configured to be emplaced in a subterranean formation.

Methods and systems for determining the elemental composition of formation rock are disclosed. The systems include a pulsed-neutron geochemical logging tool that is conveyed in a borehole traversing the formation. The pulsed-neutron geochemical logging tool can collect inelastic and capture neutron spectra. The inelastic and capture spectra are processed to provide the elemental composition of formation rock after removing contributions due to elements in the borehole and in the pores of the formation.

A method for determining a composition of a formation, includes characterizing by energy detected gamma rays resulting from interaction of neutrons that irradiated the formation. Elemental yields are determined by spectrally analyzing the energy characterized gamma rays. A subset of the elemental yields is selected as background yields. The background yields are filtered. An apparent contribution of the filtered background yields to the characterized gamma rays is determined. Foreground elemental yields are determined by spectrally analyzing the characterized gamma rays having the apparent contribution removed.

A method for determining a petrophysical property of a formation includes detecting gamma rays at two different spaced apart positions from a position of emitting neutrons into the formation at an energy level sufficient to induce inelastic scatting gamma rays. The neutrons are emitted in a plurality of bursts of neutrons into the formation, the bursts each having a first selected duration. Each burst is followed by a wait time having a second selected duration, the gamma rays detected during each of the bursts and each of the wait times. A ratio of numbers of gamma rays detected during the bursts is determined (burst ratio). A ratio of numbers of gamma rays detected during the wait times is determined (capture ratio). The burst ratio is used to correct the capture ratio. The petrophysical property is determined from the corrected capture ratio.

A tomographic imaging apparatus utilizes Compton backscattering to evaluate cement behind the casing. The imaging apparatus includes a slant-hole or pin-hole collimator coupled to a series of detectors in order to count the number of photons that backscatter off from the cement. The number of backscattered photons is proportional to the density of the cement behind the casing. Using the photon count, an image processing unit of the imaging apparatus generates a 2D or 3D tomographic image of the borehole.

Systems, methods, and devices for evaluating an earth formation intersected by a borehole. Apparatus may include at least one radiation detector configured to generate an analog electrical signal responsive to a plurality of radiation events, comprising absorption of incident ionizing radiation at a corresponding energy level, and an ionizing radiation spectrometer configured to convert each analog electrical signal from the at least one radiation detector into a plurality of digital signal pulses corresponding to the radiation events and resolve the plurality of digital signal pulses into radiation count information representative of the radiation events. Spectrometers include an input channel for each detector of the at least one radiation detector comprising an analog-to-digital converter (ADC) and configured to convert the analog electrical signal for each detector into the plurality of digital signal pulses; and at least one processor configured to generate the radiation count information.

The inelastic and capture ratio is optimized for porosity measurements in downhole applications. Pulsed-neutron data is acquired using a pulsed-neutron downhole tool. At each sampling point or log depth, the inelastic count rates and capture rates are computed. The inelastic count rate is corrected for the capture count background to increase porosity sensitivity. The capture count rate is computed by summing a range of time windows in the decay curve. In this process, the inelastic and capture responses are matched for borehole sensitivity. The ratio of inelastic and capture counts is computed. This ratio is the input to the characterized transform algorithm to compute measured porosity.

The present disclosure describes a method for surveillance of a horizontal well, including: monitoring a first set of measurement data from a pulsed neutron tool and a second set of measurement data from an array tool, wherein: the first set of measurement data indicate a holdup of the second liquid globally inside the horizontal well, and the second set of measurement data show a plurality of velocities measured at a set of corresponding locations inside the horizontal well; and interpolating the first set of measurement data to identify an interface between the first liquid and the second liquid; establish an estimated holdup of the second liquid in the cross-section of the horizontal well; and combining the estimated holdup of the second liquid with velocities measured at locations inside the horizontal well that correspond to the second layer to generate a flow weighted estimate of the second liquid inside the horizontal well.

A method and system for determining a density. The method may comprise disposing a nuclear density tool into a wellbore, performing a spectral deconvolution, determining an energy channel for a first measurement layer, recording a count rate with the gamma detector for the first measurement layer, applying a slope operator to the count rate, and identifying a first density of the first measurement layer. The system may comprise a nuclear density tool that includes a gamma source and a gamma detector configured to record a count rate, wherein the gamma detector and the gamma source are disposed on a longitudinal axis of the nuclear density tool. The system may also comprise an information handling system.