A tubular defines a central flow passage. A camera has an aperture and attached to an outer surface of the tubular with the aperture oriented away from the outer surface of the tubular. A lost circulation media reservoir is circumferentially surrounding at least a portion of the outer surface of the tubular. The lost circulation media reservoir is adjacent to the camera. The lost circulation media reservoir includes actuable gates along a periphery of the lost circulation media reservoir. A trigger is communicably coupled with the actuable gates and configured to actuate the actuable gates.

An internal assembly (230) for a tool (200) includes a retainer (232) that at least partially defines an axial bore (238). The retainer (232) further defines a port (246) providing a path of fluid communication from an exterior of the retainer to the bore (238). The internal assembly (230) also includes an electromagnet (250) coupled to the retainer (232). The electromagnet (250) is configured to actuate between an on state and an off state and to attract magnetic debris in a fluid when in the on state. The internal assembly (230) also includes a sleeve (260) that is configured to be positioned downstream from the retainer (232). The sleeve (260) at least partially defines the bore (238). The sleeve (260) further defines a port (262) that provides a path of fluid communication from the bore (238) to an exterior of the sleeve (260). The internal assembly (230) also includes a valve (270) configured to be positioned downstream from the port (262) in the sleeve (260).

A computer system, computer, and method for converting time series real-time drilling data to a drilling dysfunction prediction, utilizing machine learning layered on top of deep learning with data processing and trend analysis therebetween.

A system can provide for determining characteristics loss in a wellbore. The system can include a processor and a non-transitory memory with instructions that are executable by the processor for causing the processor to execute operations. The operations can include receiving, from sensors in a wellbore, data corresponding to loss indicators. The operations can include determining a loss probability for each loss indicator. The operations can include determining a total loss probability of fluid loss in the wellbore based on the loss probabilities. The operations can include outputting the total loss probability to be used in a drilling operation in the wellbore.

The present disclosure relates to a composite fluid including an electrically insulating foundation fluid having a dielectric constant and a dielectric strength, and an additive combined with the foundation fluid that results in a composite fluid having a dielectric constant and a dielectric strength greater than the dielectric constant and the dielectric strength of the foundation fluid.

The present disclosure relates to a composite fluid including an electrically insulating foundation fluid having a dielectric constant and a dielectric strength, and an additive combined with the foundation fluid that results in a composite fluid having a dielectric constant and a dielectric strength greater than the dielectric constant and the dielectric strength of the foundation fluid.

A method for controlling the permeability of an oil well includes the steps of preparing a polymerizable bicomponent system having at least a fluid with at least an olefinically unsaturated first polymerizable compound; optionally, at least one radical polymerization initiator I.sub.A, the initiator I.sub.A being activated thermally or in the presence of an accelerating compound and a fluid with a radical polymerization activator, the activator being selected from: a radical polymerization initiator I.sub.B for polymerizing the polymerizable compound, the initiator I.sub.B having an activation temperature equal to or lower than the temperature of the thief zone, an accelerator of the initiator I.sub.A, The method further includes injecting one of the fluids into the well annulus until the thief zone is reached, and injecting the remainder into the tubular element, until it comes into contact with the fluid injected through the annulus to form a blocking polymer at the thief zone.

A method of drilling a wellbore may include drilling the wellbore using a wellbore fluid that has rheological property values for 6 rpm, 10 minute gel, Yield Point, and/or 10 minute-to-10 second gel ratio that are +/20% of the mean values across a temperature range from 40° F. to 300° F.; and conditioning the wellbore with less than 2 hole volumes. The wellbore fluid may include an oleaginous external phase; a non-oleaginous internal phase; an amidoamine emulsifier stabilizing the non-oleaginous internal phase within the oleaginous external phase; at least two oil wetting agents; a rheology modifier; and a weighting agent having a d50 ranging from 5 to 10 μm.

A method of drilling a wellbore may include drilling the wellbore using a wellbore fluid that has rheological property values for 6 rpm, 10 minute gel, Yield Point, and/or 10 minute-to-10 second gel ratio that are +/20% of the mean values across a temperature range from 40° F. to 300° F.; and conditioning the wellbore with less than 2 hole volumes. The wellbore fluid may include an oleaginous external phase; a non-oleaginous internal phase; an amidoamine emulsifier stabilizing the non-oleaginous internal phase within the oleaginous external phase; at least two oil wetting agents; a rheology modifier; and a weighting agent having a d50 ranging from 5 to 10 μm.

Compositions with modified tannins can be used in wellbore operations. A composition can include an oil, a modified tannin, a dimer fatty acid, an aqueous liquid, and an emulsifier, where the material is injectable into a wellbore. The modified tannin may be treated with a primary amine, secondary amine, tertiary amine, or quaternary amine. The compositions may be used as drilling fluids having enhanced yield point and fluid loss control properties.