Abstract: A fishing operation may include actuating a blind ram above the wellhead to seal around the wireline; pulling out a portion of the wireline out of the wellhead; cutting the portion of the wireline; rigging up a coiled tubing blowout preventer on top of the blind ram; connecting a wire within a coiled tubing to the wireline; connecting a coiled tubing bottom hole assembly to the coiled tubing; opening the blind ram and running in hole the coiled tubing into the wellbore; pulling, with the wire, the wireline inside the coiled tubing as the coiled tubing is lowered into the wellbore; lowering the coiled tubing to reach a depth within the wellbore containing a stall or stuck point in the tubular string; cutting the wireline with a wire cutter of the coiled tubing bottom hole assembly; and pulling out the coiled tubing with the wireline.

Abstract: A wellbore tool is conditioned between downhole deployments with a substantially continuous application of a conditioning fluid within the tool. Selectively removable caps connect to ends of the tool after its removal from the wellbore. If the tool is part of a downhole string, the caps are added after the tool is decoupled from the remainder of the string. The conditioning fluid is introduced into the tool through a fitting on one of the end caps; and while a fitting on the other end cap is opened to vent fluids resident within the tool. The caps are in sealing contact with a housing of the tool to retain the conditioning fluid inside the tool. A fluid supply system at the well site provides the conditioning fluid. Example conditioning fluids include a fracturing fluid, a completion fluid, a diluent, a solubilizing agent, an anti-scaling agent, a pH buffer, a liquid freezing point depressant, corrosion and oxidation inhibitors, oxygen scavengers, biocides, surfactants, and combinations thereof.

Abstract: A head for a well tubular. The well tubular head includes features that may be applied to a casing head or a tubing head. The well tubular head includes a bowl tubular reversibly connected with a casing connector. The bowl tubular is adapted for connecting with an uphole component of an equipment stack or other system. The bowl tubular includes a hanger profile for receiving a casing hanger or tubing hanger. The casing connector is adapted for connecting with the casing. The bowl tubular and the casing connector may be replaced independently of each other. Removable connection points for flow lines may be included on the well tubular head to facilitate changing flow lines or flow line connection points. The bowl tubular may include a drive system for rotating tubing.

Abstract: A proportional integral derivative (PID) controller implements control over a drilling system based on an integral term and a proportional term. The integral term is the integral of an operating drilling fluid pressure compared to a target drilling fluid pressure. The proportional term is the difference between an operating weight on bit and a target weight on bit. The sum of the proportional term and the integral term is multiplied by a controller parameter to determine a surface rate of penetration. A drill pipe lowering rate may be changed based on the determined surface rate of penetration, and the process may repeat in an iterative cycle until the integral term is reduced to an acceptable degree.

Abstract: A properly calibrated load-cell is critical for the safe operation of a rod-pumping system. Load readings are utilized for shutdown thresholds, and incorrect measurements can cause those safe load limits to be exceeded. Correct surface load, combined with position measurement, is also important for the diagnosis of the complete pumping system. The diagnostic method for calculating down-hole conditions presents an interesting opportunity to validate surface load measurements, even from the incorrect load measurements themselves. The calculated down-hole dynamometer card will be transposed on a distinct diagonal with respect to both load and position, if the input surface load measurements are incorrect. A load offset can then be identified from this shifting and the surface load measurements can be corrected.

Abstract: A running tool having an annulus seal assembly and casing hanger attached thereto may be sent into to the wellhead to lock and preload the casing hanger in a single trip. The running tool may be rotated a first time to drop the annulus seal assembly on the casing hanger, a first pressure may be applied axially above the annulus seal assembly to set the annulus seal assembly, the running tool may be rotated a second time to close a gap between the annulus seal assembly and the wellhead, and a second pressure may be applied axially above the annulus seal assembly to preload the casing hanger.

Abstract: A slip assembly includes a first support cone configured to move a first extension ramp between retracted and extended positions. The first extension ramp is biased towards the retracted position by a first biasing member. The slip assembly further includes a second support cone configured to move a second extension ramp between retracted and extended positions. The second extension ramp is biased towards the retracted position by a second biasing member. The slip assembly further includes a slip member disposed between the first extension ramp and the second extension ramp. The slip member is configured to slide between retracted and extended positions along an outer surface of the first extension ramp and along an outer surface of the second extension ramp. A shank of the slip member is held in a cage by a retainer that moves radially when the slip member moves between the retracted and extended positions.

Abstract: The invention relates to a rotary drive arrangement for a drill rod having an outer pipe and an inner rod running at least in sections inside the outer pipe, in particular for double-head and/or overburden drilling, with a first gearbox for driving the inner rod in a rotating manner and a second gearbox for driving the outer pipe in a rotating manner, wherein the first gearbox and the second gearbox are independent of each other. According to the invention provision is made in that the first gearbox and the second gearbox are supported in a common gearbox housing and are surrounded by the same.

Abstract: A drill string system includes a drill bit disposed at a distal end of a drill string. A clutch is coupled with the drill bit. A mud motor is coupled to the clutch, and the mud motor is operable to receive a drilling fluid therein and transfer torque to the drill bit through the clutch. The clutch disengages upon application of a torque exceeding a predetermined threshold.

Abstract: A hydraulic drive for a drilling apparatus includes a hydraulic motor that drives a drill and is connected to a main pump via a first and a second working line in a closed hydraulic circuit. The main pump has a steplessly adjustable displacement volume that is adjustable by an actuating cylinder that is connected to a control valve, which has a first feed connector and a first return connector. The first feed connector is connected to an outlet connector of a pressure reducing valve such that the pressure at the feed connector is adjustable to a predefined setpoint pressure by means of the pressure reducing valve. The setpoint pressure is set in a manner which is dependent on a desired high pressure in the closed circuit.

Abstract: In one of its example aspects the technology disclosed herein concerns a wellhead lubricator. In an example embodiment and mode the wellhead lubricator comprises a yoke housing; a first clamp; a second clamp; and, an extensible actuator. The yoke housing comprises a first end configured for connection to a barrel housing and a second end configured for connection to a wellhead. The yoke housing defines a yoke cavity through which a barrel rod extends along an axis of the yoke cavity. The first clamp is situated in the yoke cavity and is configured for selective engagement with the barrel rod. The second clamp is also situated in the yoke cavity and is configured for selective engagement with the barrel rod. The extensible actuator is connected to at least one of the first clamp and the second clamp. The extensible actuator, the first clamp, and the second clamp are configured to be operated in coordinated manner to provide translation of the barrel rod along the axis of the yoke cavity.

Abstract: A hydraulic energy transfer system including an isobaric pressure exchanger (IPX) configured to exchange pressure between a first fluid and a second fluid. The IPX includes a channel formed by the IPX. The IPX is designed to direct the first fluid to a first opening of the channel and the second fluid to a second opening of the channel. The IPX further includes a barrier disposed within the channel. The barrier is designed to reduce mixing of the first fluid and the second fluid while exchanging pressure between the first fluid and the second fluid within the channel.

Abstract: A segmented backup ring including a plurality of individual segments each having curved surfaces that define an arcuate portion of the ring, each segment including a body section having the arcuate profile and defining a receptacle therein having a circumferential dimension, a projection section having a head portion and a neck portion and extending from the body section in a circumferential direction of the ring, the projection section being receivable and retainable in the receptacle of an adjacent segment body section, and the head portion having a dimension in line with the circumferential direction of the ring that is shorter than the circumferential dimension of the receptacle.

Abstract: A toe valve (1) comprising; a housing (200) having an interior and exterior; a sliding sleeve (8); a counter mechanism (2) comprising a cylinder, a ratchet piston (11, 27) with first and second ends, and a ratchet shaft (14, 28) connected to the second end; a trigger assembly (3) comprising a trigger housing, and a release piston (19), wherein the trigger assembly (3) is arranged between the counter mechanism (2) and the sliding sleeve (8), and wherein the release piston (19) is configured to activate the sliding sleeve (8), and the ratchet shaft (14, 28) is configured to activate the release piston (19), wherein the toe valve (1) further comprises; a closed chamber (15) enclosing the ratchet shaft (14, 28) and defined at least partly by the cylinder comprising a chamber fluid with a chamber pressure (P2); an inlet pressure port (6) configured to be in communication with a wellbore fluid with a wellbore pressure (P1), and wherein the first end of the ratchet piston (11, 27) is in fluid communication with the

Abstract: A downhole borehole cleaning apparatus (10) for recirculating drill cuttings contained in a downhole borehole is provided and has a body (10) having an outer surface for contacting downhole fluid containing said drill cuttings, the downhole fluid comprising a certain pressure within the downhole borehole (16). The body (10) has a pair of bearing surfaces (30U; 30D) spaced apart along the longitudinal axis of the body (10), and the pair of bearing surfaces (30U; 30D) comprise substantially the same maximum outer diameter (d1) which is greater than the maximum outer diameter of the rest (14) of the body (10). Each of the pair of bearing surfaces (30U; 30D) comprises a substantially constant and un-interrupted diameter (d1) around its whole outer circumference for at least a portion of its longitudinal length; this forces all of the drilling fluid to pass around that maximum outer diameter.

Abstract: A gas extraction system comprising a heater configured to receive a wellbore servicing fluid sample and discharge a heated wellbore servicing fluid sample, wherein the heater comprises an internal heat exchange surface coated with a superhydrophobic coating composition; a gas extractor configured to receive at least a portion of the heated wellbore servicing fluid sample and extract an extracted gas from the heated wellbore servicing fluid sample; and one or more detectors configured to receive at least a portion of the extracted gas and provide an analysis of the extracted gas.

Abstract: Various embodiments include methods and apparatus structured to install an optical fiber cable into a well at a well site. In a from-bottom-to-top embodiment, an anchor deployed at a selected location in a hole of the well can be used and the optical fiber cable can be pulled up to a surface of the well from the selected location. In a from-top-to-bottom embodiment, an optical fiber cable can be moved down from the surface until an end of the optical fiber cable is locked at a selected location by a catcher disposed at the selected location. With the optical fiber cable in the well, a portion of the optical fiber cable can be coupled to surface instrumentation. Additional apparatus, systems, and methods can be implemented in a variety of applications.

Abstract: Self-powered active sensing systems (SASS) for use in downhole drilling environments are disclosed. Sensor devices of the SASS can include a self-powered rotational speed sensor including a ring structure attached around a drill string. The ring rotates within a groove formed in an outer housing. Bearings on the ring are arranged to contact moveable members extending from the housing into the groove thereby causing the moveable member to generate an electrical signal representing rotational speed. The SASS can include a vibration sensor having a ring spring mounted within a housing. Spherical bearings on the outer surface of the ring are configured to contact screens that are mounted to the housing and that generate a signal representing movement of the bearing/ring from vibration. Multiple SASS units configured to wirelessly transmit sensor data can be placed along a drill string providing a distributed self-powered system for measuring downhole parameters.

Abstract: A system and methods according to which a controller communicates control signals to a first frac leg, which includes a wellhead operably associated with a first wellbore, a valve operably coupled to the wellhead, opposite the first wellbore, a frac line operably coupled to the wellhead, and a zipper module operably coupled to the frac line, opposite the wellhead. The first frac leg includes a first sub-controller that receives control signals from the controller. A grease system lubricates the first frac leg and the zipper module. The grease system includes a second sub-controller that receives control signals from the controller. A second frac leg is operably associated with a second wellbore. The second frac leg includes a third sub-controller that receives control signals from the controller. The first, second, and/or third sub-controllers may receive control signals from the controller via a communication bus.

Abstract: A wellhead may include a first back pressure valve, a second back pressure valve, and a tubing head adapter. The tubing head adapter may include a first and second back pressure valve set location that complements and engages an outer surface profile of the first and second back pressure valve, respectively. The first back pressure valve set location may be positioned below the second back pressure valve set location. A first back pressure valve receiving diameter of the first back pressure valve set location may be smaller than a second back pressure valve receiving diameter of the second back pressure valve set location. A method of isolating production tubing in fluid communication with a wellhead may include engaging a first and second back pressure valve at a first and second, respectively, back pressure valve set location of the tubing head adapter.