Determining a value indicative of hydrogen index. At least some of the example embodiments are methods including obtaining an inelastic count rate and a capture count rate of a gamma detector for a particular borehole depth in a formation, calculating a ratio of an inelastic count rate to a capture count rate for the particular borehole depth, and determining a value indicative of hydrogen index based on the ratio of the inelastic count rate to the capture count rate for the particular borehole depth.

Estimating parameters of interest of a formation, including density, porosity, and fluid saturation. Methods relate to gamma ray energy spectra calibration for a radiation detector including generating a calibration radiation spectrum using measurements of radiation with the detector in a time interval wherein the radiation comprises predominantly gamma rays emitted by decay of radionuclides produced by neutron activation reactions resulting from neutron irradiation, the time interval following a prior time interval corresponding to thermal neutrons produced from the irradiation; making at least one other radiation measurement with the detector outside the time interval; and producing a calibrated radiation measurement from the at least one other radiation measurement using the calibration radiation spectrum. The measurements may be taken in the time interval by conveying the radiation detector in the borehole at high speed and using a background gate of the detector.

A method for evaluating a formation includes determining a number of detected gamma rays resulting from imparting neutrons into a formation. The detected gamma rays are each characterized by an energy level thereof. The gamma rays are detected at a first distance from a position of imparting the neutrons into the formation. Those of the detected gamma rays attributable to neutron capture by hydrogen nuclei are removed from the number of detected gamma rays. The number of detected gamma rays having hydrogen neutron capture gamma rays removed therefrom are used to calculate a property of the formation.

The techniques as described herein result in a single set of intrinsic carbon-oxygen (CO) measurements that can be used for various borehole and formation saturation conditions, enhancing the reliability and robustness of formation evaluation in oil and gas wells. A method comprises formulating an intrinsic CO ratio for a subterranean formation, based on theoretical atomic concentrations of carbon and oxygen, and porosity and fluid saturation parameters.

Disclosed are apparatus, systems, and methods for determining the completeness of the cement sheath or gravel-pack annulus of a borehole based on gamma counts or count rates measured with a pulsed neuron tool deployed in the borehole in conjunction with a quantitative relationship between certain gamma count (rate) ratios and a parameter of completeness. In various embodiments, the determination utilizes the ratio of the net long inelastic count (rate) and the near capture count (rate), or the ratio of the net near inelastic count (rate) and the long capture count (rate). Additional apparatus, systems, and methods are disclosed.

A neutron porosity tool having an electronic neutron generator arrangement and a control mechanism used to provide voltage and pulses to an electronic neutron tube is provided, the neutron generator arrangement including: at least one vacuum tube; at least one ion target; at least one radio-frequency cavity; at least one high-voltage generator; at least two neutron detectors; at least one pulser circuit; and at least one control circuit. A method of controlling a neutron porosity tool having an electronic neutron generator arrangement and a control mechanism that provides voltage and pulses to an electronic neutron tube, the method including at least: controlling a bipolar neutron tube to produce two distinct neutron reactions; using a control circuit to modify the output of a pulser circuit; and using a plurality of neutron detectors to determine formation response offsets.

Methods, tools, and systems for determining two-phase borehole fluid holdup using pulsed neutron (PN) measurements are described. Embodiments of the techniques involve using formation models that are extended/extrapolated (or remodeled) to a value of 100 p.u., which correlates to the borehole environment where there is no formation matrix present. Those models can be used to determine the fractional relationship of oil and water in the borehole based on carbon and oxygen ratios provided by the PN measurement.

The present disclosure is directed to methods for evaluating a gravel pack, a frac-pack, or cement in a wellbore. In at least one embodiment, a method for evaluating a gravel pack, frac-pack or cement in a wellbore, includes pumping a first material into the wellbore, wherein the first material comprises a first tracer that is not radioactive. The method includes pumping a second material into the wellbore, wherein the second material comprises a second tracer that is not radioactive. The method includes obtaining a set of data using the downhole tool in the wellbore after the first and second materials are pumped into the wellbore. The method includes obtaining a baseline using the downhole tool in the wellbore in a depth interval without the first or second material. The method includes comparing the set of data with the baseline.

Methods and systems for determining bulk density and/or neutron porosity of a formation are described herein. The methods and systems use a pulsed neutron (PN) tool and may be performed with a tool having a single gamma detector though tools with multiple detectors may be used as well. The PN tool may be a geochemical logging tool. The methods and systems involve partitioning the time spectrum into pluralities of bins that are indicative of non-clay mineral elements and of shale/clay to the overall bulk density.

Methods and systems for determining formation salinity using pulsed neutron (PN) tools are described. Embodiments of the described methods involve binning chlorine yields or chlorine count rates arising from capture events into early and late capture regimes, which may be used to attribute the events to either the borehole or the formation.