A jarring apparatus includes first and second jarring assemblies which are axially moveable relative to each other between first and second axial configurations, and a thrust assembly interposed between the first and second jarring assemblies to limit relative axial movement therebetween at the second axial configuration and permit axial loading in one axial direction to be transferred between the first and second jarring assemblies via the thrust assembly. The apparatus further includes a jarring mass axially moveable within the jarring apparatus in reverse first and second directions upon relative rotation between the first and second jarring assemblies.

A downhole device comprising a novel apparatus and vibratory assemblage that initiates and maintains mechanical agitation within the horizontal section of a well bore by providing both low and high vibration, in multiple axes and planes, and through pulsing of high-pressure fluids within the confines of the apparatus and drilling pipe. Through the judicious and conservative use of fluids, the present invention provides both rotationally accelerated low and high vibration and high-intensity, directed and timed pressure to reduce the cumulative friction between the drill string and bottom hole assembly on a wellbore. Additionally, the present apparatus can be preprogrammed to respond to specific commands, in response to certain predetermined conditions, to stop and start functioning at various times throughout the drilling process.

The invention provides a swivel tool for use in a wellbore. The tool comprises a tool body and a mandrel which is axially moveable relative to the tool body. The tool also comprises a lock member moveable between a first condition in which the mandrel is rotatably movable relative to tool body and a second condition in which the mandrel and a tool body are rotationally coupled. The lock member is configured to move between the first condition and second condition in response to a mechanical axial force and rotational force on the mandrel.

The disclosed embodiments include well operation evaluation systems and methods to analyze a broomstick chart of a well operation. The method includes receiving data indicative of a well operation involving deploying a conveyance to a predetermined location. The method also includes determining one or more conditions that impact deployment of the conveyance to the predetermined location. The method further includes determining a likelihood of occurrence of the one or more conditions. The method further includes determining one or more operations which, when performed by one or more tools used during the well operation, overcome the one or more conditions.

A method and system for downhole pulse generation determines an optimal frequency and, in some embodiments, amplitude of axial pressure pulses to maximize the rate of penetration. Specifically, one or more sensors may be disposed on or near an axial oscillation tool that provides near real-time raw sensor data relating to speed, velocity, and acceleration of the tool. With this sensor data, an optimal set of parameters, namely an optimal frequency and, in some embodiments, amplitude may be determined based on the hydraulic conditions and frictional forces of the actual drilling environment. An optimizing control system may directly communicate these parameters to the axial oscillation tool or pass the parameters to an axial oscillation tool control system that controls the operation of the tool. Advantageously, frictional forces may be substantially reduced, the rate of penetration may be substantially enhanced, and power consumption may be intelligently managed.

A friction reduction system includes a housing including a central axis and a central passage, a valve disposed in the housing and including a first valve body and a second valve body wherein the first valve body is permitted to rotate relative to the second valve body, and a mandrel coupled to the second valve body and permitted to travel axially relative to the housing, wherein a first net pressure force is applied against the mandrel that corresponds to a drilling fluid pressure of a drilling fluid in response to flowing the drilling fluid through the valve and transitioning the valve from a closed configuration to an open configuration, and wherein a second net pressure force is applied against the mandrel that corresponds to a wellbore fluid pressure in response to flowing the drilling fluid through the valve and transitioning the valve from the open configuration to the closed configuration.

A drilling apparatus and a method for releasing rods stuck in surrounding ground use a torsional device for releasing the drilling assembly and induce centrifugal forced vibrations and bending vibrations in the drilling rods, facilitating the release from positions stuck inside the drilled hole. The apparatus allows the available power of the motor drilling device to be fully applied for generating periodic forced vibrations useful for detaching the drilling rods stuck in the surrounding ground.

A fluidic agitator includes a seamless insert body having an outer enclosure wall defining an enclosed cavity and a plurality of inner channel walls arranged to define an inlet chamber, a vortex chamber, and a feedback chamber within the enclosed cavity. The inlet chamber, the vortex chamber, and the feedback chamber create a hydraulic pulse in a fluid stream received in the enclosed cavity.

A convertible composition comprising a nanosilica drilling fluid, the nanosilica drilling fluid comprising an aqueous based drilling mud, where the aqueous based drilling mud comprises water, and an alkaline nanosilica dispersion, where the alkaline nanosilica dispersion comprises nanosilica; and a chemical activator, the chemical activator operable to hydrolyze in the presence of water to produce an acid, where a weight ratio of the alkaline nanosilica dispersion to the chemical activator is between 1 to 0.001 and 1 to 0.25.

A downhole tool string for conveying within a wellbore, including an engagement device for engaging a downhole feature located within the wellbore, a first actuator for applying a substantially non-vibrating force to the engagement device while the engagement device is engaged with the downhole feature, and a second actuator for applying a vibrating force to the engagement device while the engagement device is engaged with the downhole feature.