Abstract: Systems and methods for managing flowback fluids produced during a flowback process in a well are provided. The system includes a well formed in a target zone in a hydrocarbon reservoir, where the well also extends to a disposal zone. The system also includes a check valve or zonal isolation systems. The method includes selecting a disposal zone, directing the formation of a well extending through a target zone and a disposal zone, transporting the flowback fluid from the target zone to the disposal zone during the flowback process, and selectively plugging the well near the disposal zone to prevent migration of the flowback fluid.

Abstract: A non-electric explosive device includes a primary body containing cutting material and including a primary charge positioned in the cutting material; an explosive body at a first axial end of the primary body and including explosive material; and a firing head at a second axial end of the primary body, the firing head including a firing pin secured at least partially inside the firing head via securing device, the firing pin comprising an activating end proximate the primary charge and a blunt end protruding from a distal end of the firing head. A force applied to the blunt end of the firing pin causes the firing pin to retract toward the primary charge and break the securing device so that the activating end of the retracting firing pin impacts the primary charge which ignites the explosive material that causes the cutting material in the primary body to travel radially outward.

Abstract: A clamp assembly device for connecting a rotating control device bearing assembly to a main body of a rotating control device. The device includes clamp members configured to retain the bearing assembly in place on the main body, a clamp actuator for driving clamping and unclamping of the clamp members and a lock pin controlled by a lock pin actuator. The lock pin actuator is configured to lock and unlock the clamp assembly device by moving the pin between locked and unlocked positions along an axis substantially parallel with the axis of rotation of the bearing assembly.

Abstract: An apparatus includes a tool body having a bore that is aligned with a lengthwise axis and a rotating assembly coupled to the tool body. The rotating assembly includes a turbine wheel that is disposed adjacent to an inner surface of the wall and exposed to the bore. The rotating assembly includes an impeller that is disposed adjacent to an outer surface of the wall in a position corresponding to the turbine wheel. Each of the turbine wheel and impeller has a respective axis of rotation that is transverse to the lengthwise axis. The rotating assembly includes a link rod that couples the turbine wheel to the impeller and is used to transfer mechanical energy generated by the turbine wheel to the impeller. The apparatus is operable by fluid flow through a drill string to increase pressure in a wellbore annulus and enhance transportation of formation cuttings up the annulus.

Abstract: A horizontal drilling machine with an in-situ detection device, including a support frame, an armored cable, a steel pipe-straightening mechanism, a steel pipe-feeding mechanism, a motor, a power head, a drill pipe, a rotating chuck, a damper, a non-core drilling tool, the in-situ detection device, a fishing device and a thrust cylinder. The steel pipe-straightening mechanism, the steel pipe-feeding mechanism, the rotating chuck and the damper are sequentially fixed on the support frame from left to right. One end of the thrust cylinder is hinged with the support frame, and the other end is connected to the power head. The active drill pipe of the power head is connected to the drill pipe. An end of the armored cable is connected to the fishing device in the drill pipe, and the fishing head of the fishing device is connected to the spearhead of the non-core drilling tool.

Abstract: A method of mud logging is disclosed which the chemical constituents and concentrations of formation fluid are calculated based on pulse power plasma parameters and the constituent species and concentrations of drilling mud, including reaction products, upon which the pulse power plasma has acted. Based on correlation between pulse power plasma parameters, including drilling parameters, drilling can be optimized for identified formation and formation fluid species. An offset between the chemical makeup of the drilling mud exposed to pules power plasma and the chemical makeup of formation fluid is calculated. Based on the calculated offset, pulse power plasma drilling can be controlled as a function of drilling mud concentration including in other wellbores in the formation or field.

Abstract: A method for producing fluid from a well includes inserting a pump into a well tubing having at least one gas lift valve disposed at a selected depth. The pump arranged to lift fluid below the pump into the well tubing. A gas pressure in an annular space between the well tubing and a well casing is increased until the gas reaches a flow port in the tubing proximate the pump. The pump is operated by continuing pumping gas so as to lift fluid from a subsurface reservoir to the selected depth of the at least one gas lift valve.

Abstract: A downhole autonomous cutting tool and methods are described. The downhole autonomous cutting tool including: a body comprising a hydraulic motor, the body having a generally cylindrical configuration such that the body limits a downhole flow of fluids past the autonomous cutting tool between the autonomous cutting tool and the pipe when the tool is deployed in the pipe; a locking unit attached to the body, the locking unit actuable to engage inner surfaces of the pipe in the wellbore; a sensor module operable to detect interactions between the pipe and walls of the wellbore; an actuation unit attached to the body and rotatable by the hydraulic motor, the actuation unit operable to move a plurality of cutting elements between a running position and a cutting position; and a control unit in electronic communication with the sensor module, the locking unit, and the actuation unit.

Abstract: Systems and methods for accessing a wellbore of a subterranean well downhole of abandoned subterranean wellbore equipment include a re-entry guide secured to an uphole end of an overshot. The re-entry guide and overshot together form a re-entry tool. The overshot has an inner diameter gripping assembly sized to grip a tubing stub. The re-entry guide has an outer diameter sized to match a drift inner diameter of a casing of the subterranean well.

Abstract: A disconnect sub is connected at one end to a pipe for deployment into a well, where the disconnect sub is then connected to a downhole sealing device such as a plug. The disconnect sub comprises a disconnection point that has a lower tensile break value than the rest of the plug, and has a predetermined tensile break value such that the disconnection point will fail when a threshold value of axial tensile load is applied to the disconnect sub. This offers two methods of disconnection of the pipe from the plug after the plug has set—firstly, rotation of the pipe, or if rotation is not possible, overpull of the pipe in excess of the threshold will cause failure of the disconnection point and separation of the pipe from the plug.

Abstract: A downhole tool control apparatus includes a control assembly, a stroking assembly, and a pocket sleeve positioned in an outer sub. The control assembly and stroking assembly are independently slidable axially within the outer sub. The control assembly and stroking assembly slide depending on the flow rate of fluid through the downhole tool actuator. The stroking assembly includes a spline barrel having a spline projection positioned within a spline pocket formed in the pocket sleeve. The pocket sleeve and control assembly include one or more ratchet teeth positioned in the pocket sleeve such that as the flow rate is changed between a high and a low flow rate, the spline projection engages the ratchet teeth until an actuated cycle is completed, allowing the downhole tool actuator to move to an actuation position.

Abstract: Provided herein is an intervention tool and a method for fracturing multiple lateral wellbores in a well system. The intervention tool, in one aspect, includes a radial outer housing, the radial outer housing forming an interior bore configured to flow fluid, and an expansion member coupled proximate an outer surface of the radial outer housing. The intervention tool according to this aspect further includes a sliding sleeve positioned along an interior surface of the radial outer housing and engageable with the expansion member, the sleeve including a collection of slots or catches configured to move the expansion member between a radially retracted position when the sliding sleeve is in a first linear position and a radially expanded position when the sliding sleeve is in a second linear position.

Abstract: A downhole drilling system is disclosed. The system may include a drill bit including first and second electrodes electrically coupled to a pulse-generating circuit to receive pulse drilling signals, a reference sensor in proximity to the drill bit, an additional sensor uphole from the reference sensor, and a sensor analysis system communicatively coupled to the reference sensor and to the additional sensor. The sensor analysis system may be configured to obtain measurements representing responses recorded simultaneously by the reference sensor and by the additional sensor during a pulsed drilling operation in a wellbore, generate modified measurements in which effects of variations in the pulse drilling signal on the measurements representing responses recorded by the additional sensor are reduced based on the measurements representing responses recorded by the reference sensor and determine, based on the modified measurements, a characteristic of a formation downhole from the drill bit.

Abstract: The invention discloses a method for evaluating the difference in gas injection effect of gas injection wells in a carbonate reservoir, aiming at solving the problem that the difference in effect characters of gas injection wells cannot be systematically evaluated in the prior art, and realizing the purposes of systematically and completely evaluating the difference in gas injection effect in the carbonate reservoir and finding out the reason of low efficiency. By means of the invention, reasons for low gas injection efficiency corresponding to different geological classifications are obtained, systematic classification and induction are carried out on the difference in gas injection effect, and gas injection effects are effectively evaluated, so that a sufficient gas injection scheme design basis is provided for subsequent development and production increase, and a significant guiding principle is provided for later-stage gas injection and production increase of the carbonate reservoir.

Abstract: A gas lift system may be installed within a well to allow gas lift operations where gas may be injected into the annular area of the well while producing fluids through the interior of the production tubular or upon demand may be reversed so that gas may be injected into the interior of the production tubular while producing fluids to the annular region of the well. In order to allow bidirectional production on demand two types of gas lift mandrels are installed as part of the production tubular. Both types of gas lift mandrels are configured such that gas lift valves are mounted to the exterior of the mandrels. In order to facilitate the desired direction of gas flow through the two types of gas lift mandrels a plug and packer system with or with out one way valves may be utilized to direct and contain the pressurized gas flow within the well.

Abstract: A method includes performing a downhole operation in a borehole in a formation. Downhole particles and drilling mud are captured at a surface from the borehole into a screen of a shaker during the downhole operation. Input power that comprises at least one of voltage, current, and leakage current being supplied to the shaker is monitored during operation of the shaker, it is determined whether the input power exceeds a threshold as a result of change in a load on the shaker. In response to determining that the input power exceeds the threshold as the result of change in the load on the shaker, it is determined that there is a kick condition in the borehole, where the kick condition comprises a condition in which a pressure of the formation exceeds a pressure in the borehole.

Abstract: A method and apparatus for using a plurality of impact dampening discs composed of a closed cell polyurethane foam composite with polyborodimethylsiloxane as a dilatant non-Newtonian fluid dispersed through a foam matrix in a downhole setting tool to absorb the energy released during setting operations.

Abstract: A lost circulation system and a method for reducing losses of drilling fluid in a lost circulation zone of a wellbore are described. The lost circulation system includes a sheet of lost circulation material and particles of a lost circulation material. The sheet of lost circulation material has a maximum thickness of 1 millimeter, a length of one foot to one thousand feet, and a width of one inch to twenty inches. The method for reducing losses of drilling fluid in a lost circulation zone of a wellbore includes identifying the lost circulation zone, deploying a sheet of a first lost circulation material in the wellbore at the lost circulation zone, and circulating a slurry containing particles of the lost circulation material through the wellbore.

Abstract: A wellbore loss zone remediation method to reduce losses of drilling fluid in a lost circulation zone of a wellbore is described. The wellbore loss zone remediation method includes identifying a lost circulation zone in a wellbore, selecting a lost circulation fabric, selecting a lost circulation material for a slurry, disposing the lost circulation fabric in the wellbore, circulating the slurry in the wellbore, and determining if the lost circulation zone is remediated.

Abstract: A method of determining the condition of a drill string includes receiving, by a processing device and from one or more sensors coupled to a portion of a drill string at or near a surface of a wellbore, noise information. The noise information represents drilling vibrations of the drill string during drilling of the wellbore. The method also includes determining, by the processing device based on the noise information, multiple vibration modes of the drill string. The method also includes comparing, by the processing device, the vibration modes to at least one vibration mode threshold. The method also includes determining, by the processing device based on the comparison of the vibration modes to the at least one vibration mode threshold, a condition of the drill string.