Abstract: A method of hydraulic fracturing of a subterranean formation having a well bore includes steps of sequentially injecting different slurries with nano, micro and then macro sized proppants generated from coal ash into the well bore in order to enhance oil and gas production from fracking. A slurry useful in the method includes (a) water, (b) coal combustion fly ash particles that have a mean particle size (d50) of about 6 microns and (c) a surfactant.

Abstract: A method of deploying a jointed tubular string into a subsea wellbore includes lowering the tubular string into the subsea wellbore from an offshore drilling unit. The tubular string has a slip joint. The method further includes, after lowering, anchoring a lower portion of the tubular string below the slip joint to a non-heaving structure. The method further includes, while the lower portion is anchored: supporting an upper portion of the tubular string above the slip joint from a rig floor of the offshore drilling unit; after supporting, adding one or more joints to the tubular string, thereby extending the tubular string; and releasing the upper portion of the extended tubular string from the rig floor. The method further includes: releasing the lower portion of the extended tubular string from the non-heaving structure; and lowering the extended tubular string into the subsea wellbore.

Abstract: A pressure control device can include an outlet, an inlet secured to well equipment, and a swivel mechanism that permits relative rotation between the outlet and the inlet in an unlocked configuration and prevents relative rotation between the outlet and the inlet in a locked configuration. A lock device of the swivel mechanism can include circumferentially distributed teeth, and an engagement member that engages at least one of the teeth in the locked configuration. A method of operating a pressure control device can include securing an inlet of the pressure control device to well equipment, rotating an outlet of the pressure control device about a longitudinal axis of the inlet, locking a swivel mechanism of the pressure control device, thereby preventing rotation of the outlet relative to the inlet, and sealing off an annulus surrounding a tubular string extending through the inlet.

Abstract: A method of deploying a jointed tubular string into a subsea wellbore includes lowering the tubular string into the subsea wellbore from an offshore drilling unit. The tubular string has a slip joint. The method further includes, after lowering, anchoring a lower portion of the tubular string below the slip joint to a non-heaving structure. The method further includes, while the lower portion is anchored: supporting an upper portion of the tubular string above the slip joint from a rig floor of the offshore drilling unit; after supporting, adding one or more joints to the tubular string, thereby extending the tubular string; and releasing the upper portion of the extended tubular string from the rig floor. The method further includes: releasing the lower portion of the extended tubular string from the non-heaving structure; and lowering the extended tubular string into the subsea wellbore.

Abstract: A method of deploying a jointed tubular string into a subsea wellbore includes lowering the tubular string into the subsea wellbore from an offshore drilling unit. The tubular string has a slip joint. The method further includes, after lowering, anchoring a lower portion of the tubular string below the slip joint to a non-heaving structure. The method further includes, while the lower portion is anchored: supporting an upper portion of the tubular string above the slip joint from a rig floor of the offshore drilling unit; after supporting, adding one or more joints to the tubular string, thereby extending the tubular string; and releasing the upper portion of the extended tubular string from the rig floor. The method further includes: releasing the lower portion of the extended tubular string from the non-heaving structure; and lowering the extended tubular string into the subsea wellbore.

Abstract: A pressure control device can include an outlet, an inlet secured to well equipment, and a swivel mechanism that permits relative rotation between the outlet and the inlet in an unlocked configuration and prevents relative rotation between the outlet and the inlet in a locked configuration. A lock device of the swivel mechanism can include circumferentially distributed teeth, and an engagement member that engages at least one of the teeth in the locked configuration. A method of operating a pressure control device can include securing an inlet of the pressure control device to well equipment, rotating an outlet of the pressure control device about a longitudinal axis of the inlet, locking a swivel mechanism of the pressure control device, thereby preventing rotation of the outlet relative to the inlet, and sealing off an annulus surrounding a tubular string extending through the inlet.

Abstract: A pressure control device can include an outlet, an inlet secured to well equipment, and a swivel mechanism that permits relative rotation between the outlet and the inlet in an unlocked configuration and prevents relative rotation between the outlet and the inlet in a locked configuration. A lock device of the swivel mechanism can include circumferentially distributed teeth, and an engagement member that engages at least one of the teeth in the locked configuration. A method of operating a pressure control device can include securing an inlet of the pressure control device to well equipment, rotating an outlet of the pressure control device about a longitudinal axis of the inlet, locking a swivel mechanism of the pressure control device, thereby preventing rotation of the outlet relative to the inlet, and sealing off an annulus surrounding a tubular string extending through the inlet.

Abstract: A pressure control device for sealing about a tubular at a wellsite can include a rotatable member, at least two radial seals that sealingly contact the rotatable member, at least two fluid chambers, one chamber being exposed to the rotatable member between the radial seals, and a pump that pumps fluid between the chambers in response to rotation of the rotatable member. A method of operating a pressure control device at a wellsite can include providing at least two chambers in a bearing assembly of the pressure control device, and regulating pressures in the chambers via a valve system in communication with both of the chambers.

Abstract: A drilling system used with drilling fluid for drilling a wellbore has at least one choke in adjustable communication with flow from the wellbore. A programmable control device determines a flow coefficient value of the choke from a measured position value and a stored characteristic of the choke. The device then calculates a first value of the flow of the drilling fluid from the wellbore through the choke based on the flow coefficient value and a pressure differential measured across the choke. The device adjusts operation of the drilling system at least partially based on the calculated flow value. To adjust operation, the device can set the choke (or another choke) to a set flow value relative to the calculated first flow value. Density of the flow can also be determined so the device can adjust operation based on mass flow rate.

Abstract: A drilling head can include an annular seal assembly releasably secured in an outer housing, the annular seal assembly including an annular seal and an actuator that pressurizes a lubricant for delivery to an interior of the annular seal. A method can include positioning an annular seal in a drilling head, the annular seal including an inner liner having openings formed through a sidewall of the inner liner, and flowing a lubricant into an opening while the inner liner sealingly engages a tubular. In another method, the annular seal can have a minimum inner diameter for sealing engagement with a tubular, and a lubricant passage extending through the annular seal and intersecting an interior of the annular seal at a location spaced apart from the minimum inner diameter. A lubricant is flowed through the lubricant passage to the interior of the annular seal.

Abstract: A pressure control device can include an outlet, an inlet secured to well equipment, and a swivel mechanism that permits relative rotation between the outlet and the inlet in an unlocked configuration and prevents relative rotation between the outlet and the inlet in a locked configuration. A lock device of the swivel mechanism can include circumferentially distributed teeth, and an engagement member that engages at least one of the teeth in the locked configuration. A method of operating a pressure control device can include securing an inlet of the pressure control device to well equipment, rotating an outlet of the pressure control device about a longitudinal axis of the inlet, locking a swivel mechanism of the pressure control device, thereby preventing rotation of the outlet relative to the inlet, and sealing off an annulus surrounding a tubular string extending through the inlet.

Abstract: A computerized control system performs controlled pressure drilling in a formation with a drilling system according to a plan. A setup of at least the plan, the formation, and the drilling system is configured in the control system, and the setup is integrated with the drilling system. Functioning of the set up can then be conducted using one of a plurality of control modes, including an operating mode and a simulating mode. The control system functions the setup according to the operating mode for operational interaction with the setup using the integration of the setup with the drilling system. The control system can switch from the operating mode to the simulating mode for simulated interaction with the setup. The control system simulates for at least a time period the functioning of the setup according to the simulating mode using the integration of the setup with the drilling system. Current operations continue as at least one simulated operation or event is projected in the future.

Abstract: A Coriolis flow meter for a drilling system measures flow from a wellbore and/or from at least one pump into the wellbore. The meter can be disposed upstream of at least one choke used for controlling backpressure, and/or the meter can be disposed between at least one pump and the wellbore. The meter has at least one flow tube adapted to vibrate and conducts the flow at a first pressure level from an inlet side to an outlet side. A vessel encloses the at least one flow tube at least between the inlet and outlet sides and holds a second pressure level therein about the at least one flow tube. The second pressure level can be equal to or nearly equal to the first pressure level to reduce or nearly eliminate a pressure differential across the at least one flow tube. For example, the second pressure level can be elevated above environmental relative to the first pressure level to reduce a pressure differential across the at least one flow tube.

Abstract: Controlled pressure drilling of a borehole with a drilling system detects events and identifies the events as being one of a gas-at-surface event, a kick event, a high-pressure low-volume depletion event, and a gas expansion event. Parameters including flow-in, flow-out, density, and standpipe pressure are monitored. A volume increase is detected between the flow-in and flow-out, and an initiation point of the detected volume increase is identified. At this point, an event from the initiation point is identified based on the monitored parameters from the initiation point. To identify a kick event, for example, the standpipe pressure is determined to have increased from the initiation point without the density decreasing since the initiation point, and a cumulative volume value from the initiation point is determined to be above a first threshold. In response to the identified event, an action is initiated in the drilling system.

Abstract: A flow sub for use with a drill string includes a tubular housing having a longitudinal bore therethrough and a flow port through a wall thereof and a ball. The ball is disposed in the housing above the flow port, has a bore therethrough, and is rotatable relative to the housing between an open position where the ball bore is aligned with the housing bore and a closed position where a wall of the ball blocks the housing bore. The flow sub further includes a seat disposed in the housing above the ball for sealing against the ball wall in the closed position and a sleeve disposed in the housing and movable between an open position where the flow port is exposed to the housing bore and a closed position where a wall of the sleeve is disposed between the flow port and the housing bore.

Abstract: Signal communications at a drilling system generally includes communicating upwards or downwards from the rig floor. For example, signal communications upwards may comprise the control of a cementing head operation (e.g., actuating cementing head). Signal communications downwards may comprise the activation of tools and their confirmation (e.g., hole opening tools, liner hangers, and packers). Actuation may be performed via umbilicals, for example, via pressure spikes or the dropping of balls, darts, or radio-frequency identification (RFID) tags. However, issues may arise wherein, for example, a ball may not properly land to close a circulation valve. As another example, a cementing head could be over 100 feet above the rig floor, which may make it difficult for signal communications via an umbilical. Accordingly, what is needed are techniques and apparatus for activation of tools and their confirmation by a remote communication system.

Abstract: Methods and apparatus include tubing expanded to create a seal in an annulus surrounding the tubing. The tubing includes a sealing material selected to cause forming of undulations in a diameter of the tubing upon expansion of the tubing. Various factors of the sealing material such as deviations in its thickness influence sealing performance of the tubing with the sealing material.

Abstract: A drilling head can include an annular seal assembly releasably secured in an outer housing, the annular seal assembly including an annular seal and an actuator that pressurizes a lubricant for delivery to an interior of the annular seal. A method can include positioning an annular seal in a drilling head, the annular seal including an inner liner having openings formed through a sidewall of the inner liner, and flowing a lubricant into an opening while the inner liner sealingly engages a tubular. In another method, the annular seal can have a minimum inner diameter for sealing engagement with a tubular, and a lubricant passage extending through the annular seal and intersecting an interior of the annular seal at a location spaced apart from the minimum inner diameter. A lubricant is flowed through the lubricant passage to the interior of the annular seal.

Abstract: The disclosure relates to a system and method for determining whether a kick or loss has occurred from a well in real time, wherein the well has a marine diverter having a rotating control device. The marine diverter system may measure flow rate in real time of a drilling fluid entering the wellbore and provide a means of measuring flow rate of the drilling fluid out of the wellbore and riser. The marine diverter system may further determine displacement and velocity of displacement of rig heave motion in real time and use the foregoing steps, given a known internal diameter of the riser and a known external diameter of a drill pipe, and employing a drilling fluid volume balance equation: (Volumetric flow rate-in)?(Volumetric flow rate-out)?(Change in riser annular Volume per unit time)=X, to determine whether the kick or loss has occurred in real time.

Abstract: A drilling system used with drilling fluid for drilling a wellbore has at least one choke in adjustable communication with flow from the wellbore. A programmable control device determines a flow coefficient value of the choke from a measured position value and a stored characteristic of the choke. The device then calculates a first value of the flow of the drilling fluid from the wellbore through the choke based on the flow coefficient value and a pressure differential measured across the choke. The device adjusts operation of the drilling system at least partially based on the calculated flow value. To adjust operation, the device can set the choke (or another choke) to a set flow value relative to the calculated first flow value. Density of the flow can also be determined so the device can adjust operation based on mass flow rate.