An integrated nuclear sensor includes a scintillator connected directly to the photocathode of a photomultiplier tube. The scintillator may be thermally fused to the photocathode. The scintillator can be supported within a scintillator housing by a potting layer that is formed from an elastomer. The scintillator can include a reflector or a reflective coating applied to the outside surface of the scintillator. The reflective coating can be a vapor deposition coating applied to the scintillator.

A method for estimating values of well log measurements of a first selected type in wellbore sections wherein the measurements of the selected type are determined not to be valid includes establishing a linear relationship between measurements of a first selected type and measurements of a second selected type. The measurements of the second selected type are substantially valid over an entire measured axial section of the wellbore. Correct values of the measurements of the first type in the wellbore sections using measured values of the second type and the linear relationship.

A method for estimating values of well log measurements of a first selected type in wellbore sections wherein the measurements of the selected type are determined not to be valid includes establishing a linear relationship between measurements of a first selected type and measurements of a second selected type. The measurements of the second selected type are substantially valid over an entire measured axial section of the wellbore. Correct values of the measurements of the first type in the wellbore sections using measured values of the second type and the linear relationship.

Methods may include estimating the weight fractions of kerogen and inorganic mineral components of at least an interval of a subsurface formation; determining the grain density of kerogen and inorganic mineral components, wherein at least the grain density of kerogen is determined by one or more infrared measurements; and calculating the formation matrix density of at least an interval of the subsurface formation from the estimated weight fractions and the determined grain density. In another aspect, methods may include estimating the weight fractions of kerogen and inorganic mineral components of at least an interval of a subsurface formation; determining the grain density of kerogen and inorganic mineral components, wherein at least the grain density of kerogen is determined by one or more infrared measurements; and calculating the formation matrix density of at least an interval of the subsurface formation from the estimated weight fractions and the determined grain density; calculating the bulk density for at least an interval of the subsurface formation; and determining the total porosity of at least an interval of the subsurface formation as a function of depth by combining the calculated formation matrix density and the calculated bulk density.

Methods may include estimating the weight fractions of kerogen and inorganic mineral components of at least an interval of a subsurface formation; determining the grain density of kerogen and inorganic mineral components, wherein at least the grain density of kerogen is determined by one or more infrared measurements; and calculating the formation matrix density of at least an interval of the subsurface formation from the estimated weight fractions and the determined grain density. In another aspect, methods may include estimating the weight fractions of kerogen and inorganic mineral components of at least an interval of a subsurface formation; determining the grain density of kerogen and inorganic mineral components, wherein at least the grain density of kerogen is determined by one or more infrared measurements; and calculating the formation matrix density of at least an interval of the subsurface formation from the estimated weight fractions and the determined grain density; calculating the bulk density for at least an interval of the subsurface formation; and determining the total porosity of at least an interval of the subsurface formation as a function of depth by combining the calculated formation matrix density and the calculated bulk density.

A mounting and demounting control system is used for installing a radioactive source in nuclear logging instruments. In this system, a tail end of a truss manipulator is fixedly provided with a worktable through a bolt, a left side of an upper surface of the worktable is provided with a source capsule mounting and demounting manipulator, a right side is provided with a compression screw mounting and demounting manipulator, and the upper surface of the worktable close to the inner side of the two manipulators is respectively provided with opposed photoelectric sensors through bolts; four corners of the truss manipulator are fixed to a support through bolts, a beam is fixed between two legs at the front side of the support through bolts; and a positioning device is placed near the front of the support, and an upper part of positioning device is fixedly provided with an instrument.

A mounting and demounting control system is used for installing a radioactive source in nuclear logging instruments. In this system, a tail end of a truss manipulator is fixedly provided with a worktable through a bolt, a left side of an upper surface of the worktable is provided with a source capsule mounting and demounting manipulator, a right side is provided with a compression screw mounting and demounting manipulator, and the upper surface of the worktable close to the inner side of the two manipulators is respectively provided with opposed photoelectric sensors through bolts; four corners of the truss manipulator are fixed to a support through bolts, a beam is fixed between two legs at the front side of the support through bolts; and a positioning device is placed near the front of the support, and an upper part of positioning device is fixedly provided with an instrument.

A method for defining a permissible borehole curvature includes determining curvature characteristics of at least one of a borehole and a downhole assembly in the borehole and calculating an envelope of permissible borehole curvatures from a predetermined location in the borehole based on the curvature characteristics, a direction of the borehole at the predetermined location in the borehole, and a turning angle of the borehole relative to the direction of the borehole at the predetermined location.

A system may include a downhole tool conveyable into a wellbore on a conveyance, and a plurality of sensing devices positioned at a distal end of the downhole tool to emit wave energy in an axial direction within the wellbore. At least a portion of the wave energy are reflected by one or more wellbore hazards and received by the plurality of sensing devices. The system further includes a data acquisition system communicatively coupled to the downhole tool to receive and process reflected wave energy and thereby identify the one or more wellbore hazards.

A scintillator can include an elpasolite scintillator compound. The scintillator can be doped with a Group 2 element, and may also include an activator. The scintillator has an improved core valence luminescence at room temperature as compared to a corresponding elpasolite scintillator compound without the Group 2 dopant. The elpasolite scintillator compound can have significant core valance luminescence at a temperature higher than 125° C. In a particular embodiment, the elpasolite scintillator compound can include Cl and may or may not also include another halide, such as Br or I. The scintillator can be part of an apparatus that detects gamma radiation and neutrons and may allow a relatively simpler pulse discrimination technique to be used to a higher temperature, such as 125° C. to 150° C. before a relatively more complex pulse discrimination technique would be used.