Abstract: A drilling system including a sensor configured to monitor at least one drilling parameter, and configured to generate a signal based on the at least one drilling parameter. An encoder is in communication with the sensor, and the encoder is configured to convert the signal into a modulation signal. A flow modulator is configured to channel drilling fluid therethrough. The flow modulator includes at least one stator element and a rotor element configured to freely rotate relative to the at least one stator element as the drilling fluid flows past the rotor element. A braking system is in communication with the encoder, and the braking system is configured to selectively decrease a rotational speed of the rotor element based on the modulation signal such that an encoded acoustic signal is emitted from the flow modulator through the drilling fluid.

Abstract: A method for maintaining pressure in a wellbore drilled from a drilling platform floating on a body of water includes the steps of pumping fluid at a determined flow rate into a drill string disposed in a wellbore and measuring fluid pressure within a fluid discharge line of fluid returning from the wellbore. The fluid discharge line has a variable length corresponding to an elevation of the floating platform above the bottom of the body of water. The wellbore pressure is determined at a selected depth in the wellbore or at a selected position along a drilling riser or variable length portion of the fluid discharge line using known parameters/methods. The determined wellbore pressure is adjusted for changes in length of the fluid discharge line corresponding to changes in the elevation of the floating platform relative to the bottom of the body of water.

Abstract: A smart load pin may be configured to measure a load on a hook of a draw-works system. The smart load pin may also include circuitry to convert the measured load to a digital value representative of the measured load, wherein the digital value represents the value of the measured load in engineering units and to transfer the digital value representative of the measured load to a control system located at a derrick. The data from the smart load pin may be used in adjusting, with a control system, operation of the draw-works system based, at least in part, on the received digital value representative of the measured load.

Abstract: A pressure gauge system and a method for in-situ determination of a wellbore formation pressure through a layer of cement, comprising; a housing arranged to be permanently installed in said cement on the outside of a wellbore casing, comprising; a pressure transfer means between a first oil filled chamber and a pressure sensor, to isolate said pressure sensor from said oil filled chamber, and a pressure permeable filter port in hydrostatic connectivity with said first oil filled chamber, and a porous string extending from said filter port, said string has a higher porosity and a higher hydrostatic connectivity than said cement for said formation fluid, and is arranged to transfer said formation fluid when it is embedded in said cement.

Abstract: A method for determining formation pressure during exploratory drilling for oil includes generating a series of negative pressure shock waves at successively increasing well pressures to characterize gas kick forming at the bottom of a well. Once the lower end of the gas kick has been formed, the well pressure level as detected by a pressure sensor near the surface of the well is used to calculate the formation pressure along with the weight of the fluid column located in the well.

Abstract: Surface equipment of a cement analysis system (CAS) estimates a first drilling fluid slowness (FSLO) and a first drilling fluid acoustic impedance (ZMUD) based on a type and density of wellbore drilling fluid. A second FSLO is estimated based on a thickness and diameter of wellbore casing and transit time for energy emitted by a downhole tool to travel to and from the casing. An FSLO graphical interface is generated based on the first and second FSLO. A second ZMUD is estimated based on the drilling fluid type and density and one of the first and second FSLO selected utilizing the FSLO graphical interface. A ZMUD graphical interface is generated based on the first and second ZMUD. The downhole tool then obtains log data utilizing at least one parameter selected utilizing the ZMUD graphical interface. The log data includes a final ZMUD measured with respect to wellbore depth.

Abstract: A fluid pressure pulse generator for a downhole telemetry tool comprising a stator and a rotor. The stator has a stator body and a plurality of radially extending stator projections spaced around the stator body, with adjacently spaced stator projections defining stator flow channels extending therebetween. The rotor has a rotor body and a plurality of radially extending rotor projections spaced around the rotor body, with adjacently spaced rotor projections defining rotor flow channels extending therebetween. The rotor projections are axially adjacent the stator projections. The rotor is rotatable relative to the stator and is configured to oscillate from an open flow position an equal span of clockwise and counter clockwise rotation to first and second restricted flow positions.

Abstract: A latching assembly has a tubular housing having an outer surface and an inner surface that defines an inner bore. Latch members are carried by the housing that have a latch position that extends out from the outer surface and a release position that is retracted from the latch position. A plurality of gripping members are pivotally attached to the housing. The gripping members are pivotally attached to the tubular housing and move between a gripping position wherein the gripping members extend into the inner bore and a retracted position. An actuator engages the latch members and the gripping members and moves between a first position and a second position. The actuator moves the latch members from the latch position to the release position and the gripping members from the retracted position to the gripping position as the actuator moves from the first position to the second position.

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 directional drilling system includes a bottomhole assembly having a drill bit and a steering tool configured to adjust a drilling direction in real-time. The system also includes a first feedback loop that provides a first steering control signal to the steering tool, and a second feedback loop that provides a second steering control signal to the steering tool. The system also includes a set of sensors to measure at least one of strain and movement at one or more points along the bottom-hole assembly during drilling, wherein the first and second steering control signals are based in part on the strain or movement measurements.

Abstract: A method, apparatus and computer-readable medium for determining an influx at a wellbore is provided. A flowback parameter is obtained for a plurality of flowback events at the wellbore prior to a current flowback event. An average of the flowback parameter (?) and a standard deviation (?) of the flowback parameter is determined from the plurality of prior flowback parameters. An alarm threshold is set based on the determined average and the standard deviation. A current flowback parameter is measured and the influx is determined when the current flowback parameter meets the alarm threshold.

Abstract: A method for marine wellbore drilling includes pumping drilling fluid through a drill pipe in a wellbore below a bottom of a drilling riser extending from proximate the bottom of the water to a drilling platform on the surface. Drilling fluid returning from the wellbore is discharged from a position proximate the bottom of the drilling riser into a fluid line extending from the position to the platform. Drilling fluid in the fluid line is pumped from a depth in the body of water shallower than the position of discharge of fluid from the riser and at which a column of fluid in the marine drilling riser at an elevation above an intake of a pump in the fluid line exerts a dynamic fluid pressure exceeding fluid pressure at the intake of the pump. The riser fluid level is selected to provide a selected fluid pressure in the wellbore.

Abstract: A method to determine a drilling fluid density limit involves obtaining a geomechanical model of a target borehole, generating a depth of damage model of the target borehole to describe a relationship between a drilling fluid pressure and a depth of damage representing a modeled amount of yielded rock surrounding the target borehole, where the modeled amount of the yielded rock is calculated using a stress model according to a pre-determined failure criterion, and calculating, using the depth of damage model and the geomechanical model, the drilling fluid density limit as a function of the subterranean formation depth, where the drilling fluid density limit maintains the depth of damage at a target level for the target borehole, where the drilling fluid density limit corresponds to a depth gradient of the drilling fluid pressure, where the target borehole is drilled based at least on the drilling fluid density limit.

Abstract: Printed circuit board assemblies having capabilities for operating under high ampacity conditions are sometimes difficult to fabricate and lack sufficient mechanical robustness for extreme operating environments. Accordingly, printed circuit board assemblies comprise: a non-conductive substrate having a plurality of planar conductive pathways disposed thereon; an electronic component that is in electrical communication with one or more of the planar conductive pathways and is configured to supply an electrical current thereto; a superficial metallic conductor overlaying one or more of the planar conductive pathways, at least in part, the superficial metallic conductor having an electrical connection to the electronic component and also being in electrical communication with the planar conductive pathways; and a conductive element in electrical communication with the superficial metallic conductor, the conductive element being configured to withdraw electrical current from the printed circuit board assembly.

Abstract: A method and assembly to produce data pulses in a drilling fluid in a drill string. The assembly comprises a shear valve that includes a valve member mounted in a valve passage in fluid flow communication with a fluid flow conduit of a drill string to which the assembly is connectable. The valve member is connected to a reciprocation mechanism comprising a rocker, a driven crank arrangement, and a slider member that provides a sliding coupling between the crank arrangement and the rocker. The slider member is pivotally connected to the crank arrangement, is keyed to the rocker for angular displacement about a valve axis, and is radially slidable relative to the rocker, so actuation of the crank arrangement causes angular reciprocation of the rocker, and hence of the valve member, about the valve axis, to produce data pulses in the drilling fluid.

Abstract: The present disclosure relates to a downhole rotating magnetic field generator, wherein a stator assembly is formed by fixedly connecting a guiding stator, windings, and a body together, and a rotor assembly is formed by mounting a turbine rotor and a permanent magnet together. Between the stator assembly and the rotor assembly, sliding bearings are arranged and small mud passages are formed. There is no metal isolation between the rotor and the stator for cutting through the magnetic lines of force, so that the eddy current loss is relatively small. Meanwhile, with mud flowing through the passages as lubricant, overheating of the generator can be prevented and high power output can be ensured.

Abstract: A pressure pulse generating method and apparatus for use with a drill string includes a top and bottom subs for attaching the apparatus within the drill string; a power section comprising a rotor/stator; a drive assembly; and a nozzle sub which includes a nozzle assembly comprising a nozzle holder and a replaceable nozzle; and a nozzle housing having pulse openings. The nozzle holder has fluid ports which periodically align with the pulse openings as the nozzle holder rotates within the nozzle housing to achieve a desired pulse amplitude, frequency and waveform.

Abstract: A method and system for managing one or more hydrocarbon producing well sites is provided. The well site includes a hydrocarbon material flow passing through a pipe. The system includes a clamp-on flow meter and a control station. The clamp-on flow meter is operable to produce output indicative of at least one characteristic of the hydrocarbon material flowing through the pipe at the well site. The control station is separately located from the well site. The control station includes at least one processor adapted to receive the output from the clamp-on flow meter. The processor is adapted to determine one or more characteristics of the hydrocarbon material flow at each well site using a flow compositional model.

Abstract: A fluid pressure pulse generating apparatus with a pulser assembly having a pulser assembly housing enclosing a pressure compensation device. The pulser assembly housing includes an interior wall with a plurality of primary apertures therethrough and an exterior wall with a plurality of secondary apertures therethrough, the exterior wall overlying the interior wall. The primary and secondary apertures are in fluid communication with a pressure compensation mechanism in the pressure compensation device such that drilling fluid contacts the pressure compensation mechanism for equalization of pressure of a lubrication liquid contained inside the pulser assembly housing with pressure of the drilling fluid when the fluid pressure pulse generating apparatus is positioned downhole.

Abstract: A pump module for a drilling riser includes at least one pump mounted to a frame, the frame including features to couple the frame to a segment of riser. A fluid inlet is affixed to the frame. The fluid inlet is in fluid communication with an intake of the at least one pump. The fluid inlet has features to make fluid tight hydraulic connection to a fluid outlet of the riser segment when the frame is coupled thereto.

Abstract: A method for transmitting data from a downhole component includes: measuring a borehole fluid pressure by a receiver at a selected sampling rate and estimating a pressure signal transmitted through the fluid based on the sampled fluid pressures; measuring, by at least one pump stroke sensor, operation of a pump configured to advance fluid through the borehole; identifying individual stroke events from the pump stroke sensor measurement; generating a digital pump stroke signal in response to detecting one or more stroke events, each pump stroke signal including a digital time value associated with each of one or more stroke events; and transmitting the pump stroke signal to the receiver.

Abstract: An apparatus including a downhole tool for conveyance in a wellbore extending into a subterranean formation and method of use thereof. The downhole tool may include a turbo-alternator disposed in a passageway for drilling mud, and a controller to: track operating points of the turbo-alternator, determine from the operating points a flow rate of the drilling mud, and control a component of the downhole tool based on the flow rate.

Abstract: An LCM recovery system that relies on gravity and density or specific gravity differences between three of the main components of drilling fluids, i.e., the mud and chemicals, lost circulation material (LCM) or additives, and drill solids or cuttings. Fluid enters the LCM recovery tank from the well via a flow line or mud gas separator return leg. Cuttings, having a greater density than additives, tend to settle and become trapped on the input side of the LCM recovery tank. The less dense fluid and entrained or suspended LCM tends to travel over the baffle near the center of the tank. LCM can then be efficiently returned to the active mud system for reconditioning or pumping downhole again.

Abstract: A system can be constructed and operated with at least a wellbore that is connected to a gas detection system. The gas detection system can house a control module, infrared sensor, and first and second pumps in a portable case. The first and second pumps may be respectively positioned on opposite sides of the infrared sensor and configured to provide uniform sample gas flow through the infrared sensor to detect multiple different types of gasses flowing from the wellbore.

Abstract: Systems and related methods to simulate trapped annular pressure and wellhead movement during downhole drilling scenarios.

Abstract: Various methods and tools optically analyze downhole fluid properties in situ. Some disclosed downhole optical radiometry tools include a tool body having a sample cell for fluid flow. A light beam passes through the sample cell and a spectral operation unit (SOU) such as a prism, filter, interferometer, or multivariate optical element (MOE). The resulting light provides a signal indicative of one or more properties of the fluid. A sensor configuration using electrically balanced thermopiles offers a high sensitivity over a wide temperature range. Further sensitivity is achieved by modulating the light beam and/or by providing a reference light beam that does not interact with the fluid flow. To provide a wide spectral range, some embodiments include multiple filaments in the light source, each filament having a different emission spectrum. Moreover, some embodiments include a second light source, sample cell, SOU, and detector to provide increased range, flexibility, and reliability.

Abstract: A drilling rig with a position and velocity measuring tool that provides a self-adjusting auto driller usable for standard drilling and directional drilling in a wellbore. The position and velocity measuring tool has a processor and data storage with computer instructions for instructing the processor to present an operator directional drilling steering system dashboard with numerous graphic visual components which creates and uses a virtual encoder eliminating a failure point of a mechanical encoder.

Abstract: A method and an apparatus are provided for determining a local mineral grain size of a valuable mineral in a rock of a deposit or an occurrence, where the rock comprises at least one other mineral, and wherein the valuable mineral has a higher density than the at least one other mineral. The method may include: performing a drilling operation using a drill in the rock, with cuttings being produced, forming an aerosol comprising the cuttings and a gas stream, transferring the aerosol from the drill to at least one air classifier, performing stream classification, wherein at least two fractions comprising in each case particles of the cuttings that sink at the same speed are formed, and determining a property of at least one of the fractions, which fraction is used as a measure for the local mineral grain size of the valuable mineral in the rock.

Abstract: The present invention relates to apparatus and methods for remotely adjusting the drill bit hydraulic horse power per square inch (HSI). Varying the nozzle geometry remotely without the need to pull the drill string outside the hole has obvious advantage. Changing the nozzle flow geometry results in changing the nozzle HSI, which is beneficial to optimize drilling a well having different rock formations. The drill bit nozzle geometry of the present invention can be varied by causing a change of at least one physical property of the environment. The variable geometry nozzle is not limited to drill bit, it can be placed within the inner flow passage or between the inner flow passage and annular flow passage for controlling flow profile within a wellbore, a tubular string or a flow conduit.

Abstract: A method of monitoring a well for unwanted formation fluid influx is disclosed. Measurements of well outflow are acquired during a period in which drilling operations are performed for the well. Occurrences of stagnant flow events during the period are determined. An outflow signature is generated from the well outflow measurements for each stagnant flow event. The outflow signatures are displayed sequentially in time of occurrence. Each outflow signature is analyzed for an anomaly.

Abstract: A method for optimizing drilling includes initializing values of a plurality of drilling operating parameters and drilling response parameters. In a computer, an initial relationship between the plurality of drilling operating parameters and drilling response parameters is determined. A drilling unit to drill a wellbore through subsurface formations. The drilling operating parameters and drilling response parameters are measured during drilling and entered into the computer. A range of values and an optimum value for at least one of the drilling response parameters and at least one of the drilling response parameters is determined in the computer. A display of the at least one of the plurality of drilling operating parameters and the at least one of the drilling response parameters is generated by the computer.

Abstract: Expandable tools for use in subterranean boreholes may include a body defining a fluid flow path extending through the body. A valve piston may be located within the fluid flow path of the body, the valve piston configured to move longitudinally within the body responsive to drilling fluid flowing through the fluid flow path above a threshold pressure. The valve piston may include a nozzle defining an opening at an end of the valve piston. A status indicator may be located within the flow path of the body, the status indicator being fixed relative to the body. The status indicator may be positioned and shaped to alter a cross-sectional area of the opening of the nozzle by at least partially entering the nozzle responsive to the valve piston moving longitudinally within the body.

Abstract: Air compressor systems, upgrade kits, computer readable medium, and methods for controlling an air compressor for improved performance. The methods may include receiving a working air requirement; determining an estimated air pressure of the air compressor to deliver the working air requirement; measuring a pressure of the air compressor; comparing the measured pressure with the calculated estimated air pressure; if the measured pressure of the air compressor is greater than the determined estimated air pressure by a predetermined greater amount, then decreasing an output control of the air compressor; and if the measured pressure of the air compressor is less than the calculated estimated air pressure by a predetermined lesser amount then increasing the output control of the air compressor. The air compressor may be controlled based on a measured pressure of delivered working air. An oil control system may shut off oil to parts of the air compressor.

Abstract: A downhole assembly for directionally drilling a borehole has a motor, a transmission, and a steering mechanism. The motor has a rotor driven in a stator by flow of drilling fluid therebetween. The transmission operatively couples the rotor to a drill bit for drilling the borehole. A flow control controls the flow of drilling fluid through an internal passage of the rotor. The flow control can thereby vary the drive of the rotor in a bit speed effect that preferentially cuts the wall of the borehole to achieve directional drilling. The flow control can also thereby create a differential pressure displacing the rotor along a longitudinal axis of the motor in a thrust effect. The steering mechanism responds to the displacement of the rotor and deviates a direction of the drill bit from the longitudinal axis of the motor to further achieve directional drilling. The bit speed effect, the rotor displacement, and the deviation are preferentially coordinated to coincide or at least operate together.

Abstract: Rock strength is estimated during drilling using a rate of penetration model or a modified mechanical specific energy models. The rock strength estimate can be used in conducting further drilling, for example by a drilling system. Drilling parameters may be altered as a result of determining rock strength, for example to avoid undesirable trending fractures, such as extensive vertical fractures.

Abstract: A method of drilling a wellbore includes deploying a drill string into the wellbore through a casing string disposed in the wellbore. The casing string has a pressure responsive element and a hydraulic line in communication with the element and extending along the casing string. The method further includes: drilling the wellbore into a formation by injecting drilling fluid through the drill string and rotating a drill bit of the drill sting; and while drilling the formation, monitoring a pressure of the hydraulic line to ensure control of the formation.

Abstract: A drilling system (10) including a drill string (13) which extends from a floating drilling rig to a well bore, and a tubular riser (12) which surrounds at least part of the portion of the drill string (13) between the well bore and drilling rig, the riser (12) having a telescopic joint (20) between a first tubular portion and a second tubular portion of the riser, the first tubular portion extending down to a well head at the top of the well bore and the second tubular portion extending up towards the drilling rig, the telescopic joint (20) comprising an inner tube part (20b) which is mounted within an outer tube part (20a), the drilling system (10) further including a riser closure device (26) which is mounted in the second tubular portion of the riser (12) and which is operable to provide a substantially fluid tight seal between the riser (12) and the drill string (13) whilst permitting the drill string (13) to rotate relative to the riser (12).

Abstract: An apparatus uses well devices, both downhole and at the surface, to control at least one condition in a wellbore. The downhole equipment includes flow restriction devices that modulate fluid flow along a wellbore annulus, flow bypass devices that selectively bypass fluid flow from wellbore tubular bore to the wellbore annulus, and downhole sensors that generate information relating to a selected parameter of interest. The surface equipment includes a pump that circulates a drilling fluid in the wellbore. Controllers, which may be downhole and/or at the surface, use sensor information to generate advice parameters or signals that may be used to control the flow restriction devices, the flow bypass devices, and/or the fluid circulation pump.

Abstract: An apparatus for use downhole is disclosed that, in one configuration includes a downhole tool configured to operate in an active position and an inactive position and an actuation device, which may include a control unit. The apparatus includes a telemetry unit that sends a first pattern recognition signal to the control unit to move the tool into the active position and a second pattern recognition signal to move the tool into the inactive position. The apparatus may be used for drilling a subterranean formation and include a tubular body and one or more extendable features, each positionally coupled to a track of the tubular body, and a drilling fluid flow path extending through a bore of the tubular body for conducting drilling fluid therethrough. A push sleeve is disposed within the tubular body and coupled to the one or more features.

Abstract: Core jam indicators for use with coring tools include a plug coupled with an inner barrel and configured to selectively close the entrance of the inner barrel. The plug has at least one fluid port extending through a wall of the plug between an interior and an exterior of the plug. The mandrel at least partially covers the at least one fluid port of the plug in an activated position and the at least one fluid port is at least partially uncovered by the mandrel in a deactivated position. The mandrel is coupled to the inner barrel. A piston force acting on the mandrel resulting from a pressure difference above and below the mandrel acts over an area smaller than a maximum transverse cross-sectional area of the inner barrel. Coring tools include such core jam indicators. Components are provided and assembled to form such core jam indicators.

Abstract: Embodiments of the present invention include methods and apparatus for dynamically controlling pressure within a wellbore while forming the wellbore. In one aspect, one or more pressure control apparatus are used to maintain desired pressure within the wellbore while drilling the wellbore. In another aspect, pressure is dynamically controlled while drilling using foam to maintain a substantially homogenous foam flow regime within the wellbore annulus for carrying cuttings from the wellbore.

Abstract: A fluidic modulator in accordance to an aspect includes a body forming a flow aperture between an inlet and an outlet, the flow aperture providing a constriction to a fluid flowing axially from the inlet to the outlet, and a moveable element having a shaft portion disposed through the body and a tip end selectively positionable in the flow aperture to alter the flow aperture.

Abstract: A well system includes a first fluidic modulator (FM) located at the bottom of the tubular string and a repeater fluidic modulator (FM) located in the tubular string between the first FM and the surface, the repeater FM including a body forming a flow aperture between an inlet and an outlet, the flow aperture providing a constriction to a fluid flowing axially through the tubular string, and a moveable portion operable to alter the flow aperture. To create a modulated pressure pulse the moveable portion may be for example radially shifted in the flow aperture, rotated in the flow aperture, or the rotation of the moveable portion in the flow aperture may be controlled.

Abstract: A method for forming a subsurface wellbore is disclosed. The method includes operating a drilling string in a first direction of rotation. A first motor located near the end of the drilling string is operated in a direction of rotation opposite that of the drilling string. A drill bit is rotated using a second motor that is coupled to the first motor.

Abstract: A drilling system and method for monitoring drilling parameters for an underground drilling operation.

Abstract: An installation (11) for drilling a well (13) into a soil comprising:—a discharge pipe (25) connected to the well (13) for recovering a drilling mud created by the drilling fluid mixing with components from the soil;—a flow rate sensor (92) to measure at least one parameter of the recovered drilling mud and generate a parameter value;—a calculator (94) connected to the flow rate sensor (92) to receive the parameter value in order to calculate a flow rate of the recovered drilling mud using the parameter value; characterized in that it further comprises a flume (90) having a throat and an approach channel hydraulically connected to the discharge pipe (25) to receive the recovered drilling mud, the measured parameter of the recovered drilling mud being representative of a height of the recovered drilling mud in the approach channel.

Abstract: A device for generating pressure pulses in flowing fluid includes a valve having a stem movable linearly relative to a passageway. The valve is configured to vary restriction to flow through the passageway in response to changes in relative position between the stem and the passageway. The device also includes a rotatable member in operable communication with the valve such that rotation of the rotatable member causes the stem to move, and a motion translation arrangement that is in operable communication with the rotatable member and the stem such that the stem linearly reciprocates in response to the rotatable member rotating in a single direction of rotation.

Abstract: A downhole drilling motor for well drilling operations includes a tubular housing and a stator disposed in the tubular housing. The stator defines an internal cavity passing therethrough, wherein the stator includes one or more lobes defining at least a portion of the cavity. A rotor is operatively positioned in the internal cavity to cooperate with the one or more lobes of the stator. At least a portion of the stator or of the rotor comprises a memory material adapted to expand or contract when heat is applied by a localized heating module to the memory material. A fluid escape gap between the rotor and stator is adjusted by applying heat to the rotor and/or stator. At least one controller is adapted to receive input data and provide output signals increasing and/or decreasing electrical current applied to the at least one localized heating module.

Abstract: A system and method have a choke in fluid communication with a rotating control device. The choke controls flow of drilling mud from the rotating control device to a gas separator during a controlled pressure drilling operation, such as managed pressure drilling (MPD) or underbalanced drilling (UBD). A probe is in fluid communication with the drilling mud between the choke and the gas separator. During operations, the probe evaluates gas in the drilling mud from the well passing from the choke to the gas separator.

Abstract: A method for maintaining pressure in a wellbore during drilling operations is disclosed. The method includes the steps of providing fluid from a reservoir through a drill string, circulating the fluid from the drill string to an annulus between the drill string and the wellbore, isolating pressure in the annulus, measuring pressure in the annulus, calculating a set point backpressure, applying back pressure to the annulus based on the set point back pressure, diverting fluid from the annulus to a controllable choke, controllably bleeding pressurized fluid from the annulus, separating solids from the fluid, and directing the fluid to the reservoir. An apparatus for maintaining pressure in a wellbore during drilling operations that includes an adjustable choke for controllably bleeding off pressurized fluid from the wellbore annulus. A backpressure pump for applying a set point backpressure, and a processor for controlling the adjustable choke and backpressure pump are also disclosed.