A jarring tool used to dislodge a stuck tubular string or bottom hole assembly within an underground wellbore. A funnel element is placed underground either within, or as part of, a tubular string. A deformable ball may be seated within the funnel element to block fluid from passing within the tubular string. Hydraulic pressure may build within the tubular string until it exceeds the pressure the ball can withstand. This will cause the ball to deform and be expelled through the funnel element. With no ball to block its flow, fluid will be rapidly released through the funnel element. The rapid release of fluid will cause a powerful jarring or jolting to the tubular string or bottom hole assembly. Deformed balls may be captured in a cartridge chamber installed within the drill string and sized to create turbulent fluid flow within the drill string.

A pressure pulse system includes a stator, a rotor rotatably positioned in the stator, and a valve assembly configured to induce a pressure pulse in response to rotation of the rotor within the stator, wherein the valve assembly includes a first valve plate coupled to one of the stator and the rotor and including a flow passage, and a second valve plate coupled to the other of the stator or the rotor to which the first valve plate is not coupled and comprising a first flow passage and a second flow passage that is spaced from the first flow passage, wherein the valve assembly provides a first flowpath and a second flowpath between the flow passage of the first valve plate and the second flow passage of the second valve plate.

An agitator for vibrating a drill string includes an agitator housing, a rotor and an agitation mass. The drill string has a central axis. The rotor is coupled to the agitator housing and being rotatable about an agitator axis. The agitation mass is coupled to the rotor and is rotatable about the agitator axis. During rotation, a center of mass of the agitation mass is spaced apart from the agitator axis to cause deflection of the agitator axis relative to the central axis to produce vibration in the drill string.

A casing string is augmented with one or more variable flow resistance devices or “vibrating tools” to facilitate advancement of the casing and distribution of the cement in the annulus once the casing is properly positioned. Vibrating tools in the form of plugs can be pumped down and landed inside the casing string. The method includes vibrating the casing string while advancing the casing down the wellbore or while the cement is pumped into the annulus, or both. After the cementing operation is completed, the devices may be drilled out or retrieved with fishing tools to reopen the casing string for further operations. One or more wipers may be provided on the plugs, but the section housing the flow path may be free of wipers to allow the size and flow capacity of the flow path to be optimized.

A pulsation valve system and method can include a mandrel, an oscillating valve head and a stationary valve head. The mandrel can be operably coupled to a rotor of a pulsation assembly, and can include bypass bores controlled by a spring biased piston that moves in response to a predetermined fluid pressure acting thereon. The oscillating valve head can be attached to and rotatable with the mandrel. The stationary valve head can be positioned adjacent and stationary with respect to the oscillating valve head. The stationary valve head can include a stationary valve bore defined therethrough. The oscillating valve head can include an oscillating valve bore defined therethrough that is alignable with the stationary valve bore at a predetermined rotational position. The stationary valve bore can have a radial length greater than the oscillating valve bore.

A fluid pulse generator can include a fluid motor and a bypass flow path in fluid communication with an inlet and an outlet, and a flow control device configured to permit flow through the bypass flow path in response to a predetermined pressure differential applied across the flow control device. A method of generating fluid pulses can include flowing a fluid through a fluid pulse generator, thereby generating fluid pulses, and then applying a predetermined pressure differential from an inlet to an outlet of the fluid pulse generator, thereby permitting flow of the fluid through the fluid pulse generator without generating the fluid pulses. A fluid pulse generation system can include a fluid pulse generator with a fluid motor, a variable flow restrictor, and a bypass flow path. A predetermined pressure differential applied across the fluid motor permits the flow of the fluid through the bypass flow path.

A technique facilitates controlled creation of pressure waves in a downhole environment. The technique enables creation of, for example, dynamic underbalance (DUB) pressure waves or dynamic overbalance (DOB) pressure waves which can be used to perform desired activities downhole. According to an embodiment, a pump is coupled with a pressure chamber and conveyed downhole into a borehole to a desired location. The pump may be operated downhole to change a pressure level in the pressure chamber until a sufficient pressure differential exists between an interior and an exterior of the pressure chamber. A release mechanism in communication with the pressure chamber is then rapidly opened to establish the desired pressure wave as the differing pressures equalize.

Techniques for removing a tubular from a wellbore include running a downhole tool on a downhole conveyance into a wellbore formed from a terranean surface into a subterranean formation; activating a piston sub-assembly to repeatedly move pistons to contact a portion of a casing installed in the wellbore to at least de-bond a cement layer installed between the portion of the casing and the subterranean formation from the portion of the casing; activating a cutting sub-assembly to move a cutting blade to cut through the portion of the casing adjacent the de-bonded portion of the cement layer; activating a hanger sub-assembly to move a set of slips into contacting engagement with the cut portion of the casing; and running the downhole tool on the downhole conveyance out of the wellbore with the cut portion of the casing engaged with the set of slips.

A tunable wellbore pulsation valve reduces drillstring friction in a wellbore. An upper valve plate and a lower valve plate, and upper valve plate orifice and lower valve plate orifice enabling throughflow. A Moineau motor rotates the upper valve plate while the lower valve plate remains stationary. Fluid flow causes a first fluid state of fluid passing through both the upper valve plate and the lower valve plate when the fluid passing causes rotation of the upper valve plate to align the upper valve plate orifice with the lower valve plate orifice. Increased flow efficiency produces more powerful fluid pressure pulsations and axial vibrations without increasing pump pressure at the surface of the wellbore, yielding increased wellbore friction reduction while expending the same or less energy at the surface pump than would be expended in the absence of the reduced turbulent and shear conditions and increased laminar conditions.

Techniques for removing a tubular from a wellbore include running a downhole tool on a downhole conveyance into a wellbore formed from a terranean surface into a subterranean formation; activating a piston sub-assembly to repeatedly move pistons to contact a portion of a casing installed in the wellbore to at least de-bond a cement layer installed between the portion of the casing and the subterranean formation from the portion of the casing; activating a cutting sub-assembly to move a cutting blade to cut through the portion of the casing adjacent the de-bonded portion of the cement layer; activating a hanger sub-assembly to move a set of slips into contacting engagement with the cut portion of the casing; and running the downhole tool on the downhole conveyance out of the wellbore with the cut portion of the casing engaged with the set of slips.