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WO2006138565A1 - Systeme et procede de controle actif de la pression fond de trou au moyen d'un systeme a circulation continue - Google Patents

Systeme et procede de controle actif de la pression fond de trou au moyen d'un systeme a circulation continue Download PDF

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Publication number
WO2006138565A1
WO2006138565A1 PCT/US2006/023495 US2006023495W WO2006138565A1 WO 2006138565 A1 WO2006138565 A1 WO 2006138565A1 US 2006023495 W US2006023495 W US 2006023495W WO 2006138565 A1 WO2006138565 A1 WO 2006138565A1
Authority
WO
WIPO (PCT)
Prior art keywords
pressure
wellbore
fluid
drilling
apd
Prior art date
Application number
PCT/US2006/023495
Other languages
English (en)
Inventor
Sven Krueger
Volker Krueger
Peter Aronstam
Harald Grimmer
Roger Fincher
Larry Watkins
Original Assignee
Baker Hughes Incorporated
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Baker Hughes Incorporated filed Critical Baker Hughes Incorporated
Priority to GB0724939A priority Critical patent/GB2441927B/en
Priority to CA002612111A priority patent/CA2612111A1/fr
Publication of WO2006138565A1 publication Critical patent/WO2006138565A1/fr
Priority to NO20076490A priority patent/NO343598B1/no

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Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B21/00—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
    • E21B21/08—Controlling or monitoring pressure or flow of drilling fluid, e.g. automatic filling of boreholes, automatic control of bottom pressure
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B19/00—Handling rods, casings, tubes or the like outside the borehole, e.g. in the derrick; Apparatus for feeding the rods or cables
    • E21B19/16—Connecting or disconnecting pipe couplings or joints
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B21/00—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
    • E21B21/01—Arrangements for handling drilling fluids or cuttings outside the borehole, e.g. mud boxes
    • E21B21/019—Arrangements for maintaining circulation of drilling fluid while connecting or disconnecting tubular joints
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B21/00—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
    • E21B21/10—Valve arrangements in drilling-fluid circulation systems

Definitions

  • This invention relates generally to oilfield wellbore drilling systems and more particularly to drilling systems that utilize active control of bottomhole pressure or equivalent circulating density during drilling of the wellbores.
  • Oilfield wellbores are drilled by rotating a drill bit conveyed into the wellbore by a drill string.
  • the drill string includes a drill pipe (tubing) that has at its bottom end a drilling assembly (also referred to as the "bottomhole assembly” or “BHA”) that carries the drill bit for drilling the wellbore.
  • the drill pipe is made of jointed pipes. Alternatively, coiled tubing may be utilized to carry the drilling of assembly.
  • the drilling assembly usually includes a drilling motor or a "mud motor” that rotates the drill bit.
  • the drilling assembly also includes a variety of sensors for taking measurements of a variety of drilling, formation and BHA parameters.
  • a suitable drilling fluid (commonly referred to as the "mud") is supplied or pumped under pressure from a source at the surface down the tubing.
  • the drilling fluid drives the mud motor and then discharges at the bottom of the drill bit.
  • the drilling fluid returns uphole via the annulus between the drill string and the wellbore inside and carries with it pieces of formation (commonly referred to as the "cuttings") cut or produced by the drill bit in drilling the wellbore.
  • tubing For drilling wellbores under water (referred to in the industry as “offshore” or “subsea” drilling) tubing is provided at a work station (located on [0004] a vessel or platform).
  • One or more tubing injectors or rigs are used to move the tubing into and out of the wellbore.
  • a riser which is formed by joining sections of casing or pipe, is deployed between the drilling vessel and the wellhead equipment at the sea bottom and is utilized to guide the tubing to the wellhead.
  • the riser also serves as a conduit for fluid returning from the wellhead to the sea surface.
  • the drilling operator attempts to carefully control the fluid density at the surface so as to control pressure in the wellbore, including the bottomhole pressure.
  • the operator maintains the hydrostatic pressure of the drilling fluid in the wellbore above the formation or pore pressure to avoid well blow-out.
  • the density of the drilling fluid and the fluid flow rate largely determine the effectiveness of the drilling fluid to carry the cuttings to the surface.
  • One important downhole parameter controlled during drilling is the bottomhole pressure, which in turn controls the equivalent circulating density ("ECD”) of the fluid at the wellbore bottom.
  • ECD equivalent circulating density
  • ECD describes the condition that exists when the drilling mud in the well is circulated.
  • This negative effect of the increase in pressure along the annulus of the well is an increase of the pressure which can fracture the formation at the shoe of the last casing. This can reduce the amount of hole that can be drilled before having to set an additional casing.
  • At-balance means that the pressure in the wellbore is maintained at or near the formation pressure.
  • the under-balanced condition means that the wellbore pressure is below the formation pressure.
  • one approach is to use a mud- filled riser to form a subsea fluid circulation system utilizing the tubing, BHA, the annulus between the tubing and the wellbore and the mud filled riser, and then inject gas (or some other low density liquid) in the primary drilling fluid (typically in the annulus adjacent the BHA) to reduce the density of fluid downstream (i.e., in the remainder of the fluid circulation system).
  • gas or some other low density liquid
  • the present invention provides a wellbore system wherein the bottomhole pressure and hence the equivalent circulating density is controlled by creating a pressure differential at a selected location in the return fluid path with an active pressure differential device to reduce or control the bottomhole pressure.
  • the present system is relatively easy to incorporate in new and existing systems.
  • the present invention provides wellbore systems for performing downhole wellbore operations for both land and offshore wellbores.
  • drilling systems include a rig that moves an umbilical (e.g., drill string) into and out of the wellbore.
  • the umbilical can include wires for transmitting power such as electrical downhole.
  • a bottomhole assembly, carrying the drill bit, is attached to the bottom end of the drill string.
  • a well control assembly or equipment on the well receives the bottomhole assembly and the tubing.
  • a drilling fluid system supplies a drilling fluid into the tubing, which discharges at the drill bit and returns to the well control equipment carrying the drill cuttings via the annulus between the drill string and the wellbore.
  • a riser dispersed between the wellhead equipment and the surface guides the drill string and provides a conduit for moving the returning fluid to the surface.
  • an active pressure differential device moves in the wellbore as the drill string is moved.
  • the active differential pressure device is attached to the wellbore inside or wall and remains stationary relative to the wellbore during drilling.
  • the device is operated during drilling, i.e., when the drilling fluid is circulating through the wellbore, to create a pressure differential across the device.
  • This pressure differential alters the pressure on the wellbore below or downhole of the device.
  • the device may be controlled to reduce the bottomhole pressure by a certain amount, to maintain the bottomhole pressure at a certain value, or within a certain range. By severing or restricting the flow through the device, the bottomhole pressure may be increased.
  • the system also includes downhole devices for performing a variety of functions.
  • Exemplary downhole devices include devices that control the drilling flow rate and flow paths.
  • sensors communicate with a controller via a communication link to maintain the wellbore pressure at a zone of interest at a selected pressure or range of pressures.
  • the communication link can include conductors, wires, cables in or adjacent the drill string that are adapted to convey data signals and/or electrical power.
  • the sensors are strategically positioned throughout the system to provide information or data relating to one or more selected parameters of interest such as drilling parameters, drilling assembly or BHA parameters, and formation or formation evaluation parameters.
  • the controller for suitable for drilling operations preferably includes programs for maintaining the wellbore pressure at zone at under-balance condition, at at-balance condition or at over-balanced condition.
  • the controller may be programmed to activate downhole devices according to programmed instructions or upon the occurrence of a particular condition.
  • Exemplary configurations for the APD Device and associated drive includes a moineau-type pump coupled to positive displacement motor/drive via a shaft assembly.
  • Another exemplary configuration includes a turbine drive coupled to a centrifugal-type pump via a shaft assembly.
  • a high-pressure seal separates a supply fluid flowing through the motor from a return fluid flowing through the pump.
  • the seal is configured to bear either or both of radial and axial (thrust) forces.
  • a positive displacement motor can drive an intermediate device such as a hydraulic motor, which drives the APD Device.
  • a jet pump can be used, which can eliminate the need for a drive/motor.
  • pumps incorporating one or more pistons, such as hammer pumps may also be suitable for certain applications.
  • the APD Device can be driven by an electric motor.
  • the electric motor can be positioned external to a drill string or formed integral with a drill string. In a preferred arrangement, varying the speed of the electrical motor directly controls the speed of the rotor in the APD device, and thus the pressure differential across the APD Device.
  • Bypass devices are provided to allow fluid circulation in the wellbore during tripping of the system, to control the operating set points of the APD Device and/or associated drive/motor, and to provide a discharge mechanism to relieve fluid pressure.
  • Embodiments of the present invention can be to manage wellbore pressure even when the formation is not being actively drilled.
  • embodiments of the present invention can be used to control pressure during periods where joints are added to the drill string and when the drill string is tripped into or out of the wellbore.
  • a system includes a drill string, a drilling fluid unit, a device that allows continuous circulation of drilling fluid into the wellbore, and an APD Device in communication with the drilling fluid to control pressure in the wellbore.
  • the continuous circulation device is adapted to circulate fluid while making up joints to a drill string, while tripping the drill string, and other such activities.
  • the APD Device also controls wellbore pressure when drilling is stopped for these activities.
  • wellbore pressure can be maintained below the combined pressure caused by weight of the fluid and pressure losses created due to circulation of the fluid in the wellbore, at or near a balanced pressure condition, and at an underbalanced condition.
  • the APD Device can be operated to reduce swab effect in the wellbore and/or reduce surge effect in the wellbore.
  • wellbore pressure can be controlled both during the drilling and when the drilling is stopped without substantially changing density of the fluid.
  • surface control of wellbore pressure is provided by a flow restriction device such as a choke or valve coupled to the fluid flowing out of the annulus of the wellbore. The flow restriction device selectively creates a backpressure in the wellbore that can be used to modulate wellbore pressure.
  • Figure 1A is a schematic illustration of one embodiment of a system using an active pressure differential device to manage pressure in a predetermined wellbore location
  • Figure 1 B graphically illustrates the effect of an operating active pressure differential device upon the pressure at a predetermined wellbore location
  • Figure 2 is a schematic elevation view of Figure 1A after the drill string and the active pressure differential device have moved a certain distance in the earth formation from the location shown in Figure 1A;
  • Figure 3 is a schematic elevation view of an alternative embodiment of the wellbore system wherein the active pressure differential device is attached to the wellbore inside;
  • FIGS 4A-D are schematic illustrations of one embodiment of an arrangement according to the present invention wherein a positive displacement motor is coupled to a positive displacement pump (the APD
  • FIGS 5A and 5B are schematic illustrations of one embodiment of an arrangement according to the present invention wherein a turbine drive is coupled to a centrifugal pump (the APD Device);
  • Figures 6 is a graph depicting exemplary dynamic pressure losses associated with a conventional drilling system and also a system utilizing an active pressure differential device made in accordance embodiments of the present invention
  • Figure 7 is a schematic illustration of a continuous circulation system used in conjunction with an APD Device and flow restriction device made in accordance with embodiments of the present invention
  • Figure 8 is a graph depicting exemplary dynamic pressure losses associated with a system utilizing the Fig. 7 system and also the Fig. 7 system when utilizing an active pressure differential device made in accordance embodiments of the present invention.
  • FIG. 1A there is schematically illustrated a system for performing one or more operations related to the construction, logging, completion or work-over of a hydrocarbon producing well.
  • FIG 1A shows a schematic elevation view of one embodiment of a wellbore drilling system 100 for drilling wellbore 90 using conventional drilling fluid circulation.
  • the drilling system 100 is a rig for land wells and includes a drilling platform 101 , which may be a drill ship or another suitable surface workstation such as a floating platform or a semi-submersible for offshore wells.
  • additional known equipment such as a riser and subsea wellhead will typically be used.
  • well control equipment 125 (also referred to as the wellhead equipment) is placed above the wellbore 90.
  • the wellhead equipment 125 includes a blow-out- preventer stack 126 and a lubricator (not shown) with its associated flow control.
  • This system 100 further includes a well tool such as a drilling assembly or a bottomhole assembly (“BHA") 135 at the bottom of a suitable umbilical such as drill string or tubing 121 (such terms will be used interchangeably).
  • the BHA 135 includes a drill bit 130 adapted to disintegrate rock and earth.
  • the bit can be rotated by a surface rotary drive or a motor using pressurized fluid (e.g., mud motor) or an electrically driven motor.
  • the tubing 121 can be formed partially or fully of drill pipe, metal or composite coiled tubing, liner, casing or other known members. Additionally, the tubing 121 can include data and power transmission carriers such fluid conduits, fiber optics, and metal conductors.
  • the tubing 121 is placed at the drilling platform 101.
  • the BHA 135 is conveyed from the drilling platform 101 to the wellhead equipment 125 and then inserted into the wellbore 90.
  • the tubing 121 is moved into and out of the wellbore 90 by a suitable tubing injection system.
  • a drilling fluid from a surface mud system 22 is pumped under pressure down the tubing 121 (a "supply fluid").
  • the mud system 22 includes a mud pit or supply source 26 and one or more pumps 28.
  • the supply fluid operates a mud motor in the BHA 135, which in turn rotates the drill bit 130.
  • the drill string 121 rotation can also be used to rotate the drill bit 130, either in conjunction with or separately from the mud motor.
  • the drill bit 130 disintegrates the formation (rock) into cuttings 147.
  • the drilling fluid leaving the drill bit travels uphole through the annulus 194 between the drill string 121 and the wellbore wall or inside 196, carrying the drill cuttings 147 therewith (a "return fluid").
  • the return fluid discharges into a separator (not shown) that separates the cuttings 147 and other solids from the return fluid and discharges the clean fluid back into the mud pit 26.
  • the clean mud is pumped through the tubing 121 while the mud with cuttings 147 returns to the surface via the annulus 194 up to the wellhead equipment 125.
  • casing 129 with a casing shoe 151 at the bottom is installed.
  • the drilling is then continued to drill the well to a desired depth that will include one or more production sections, such as section 155.
  • the section below the casing shoe 151 may not be cased until it is desired to complete the well, which leaves the bottom section of the well as an open hole, as shown by numeral 156.
  • the present invention provides a drilling system for controlling bottomhole pressure at a zone of interest designated by the numeral 155 and thereby the ECD effect on the wellbore.
  • an active pressure differential device (“APD Device") 170 is fluidly coupled to return fluid downstream of the zone of interest 155.
  • the active pressure differential device is a device that is capable of creating a pressure differential " ⁇ P" across the device. This controlled pressure drop reduces the pressure upstream of the APD Device 170 and particularly in zone 155.
  • the system 100 also includes downhole devices that separately or cooperatively perform one or more functions such as controlling the flow rate of the drilling fluid and controlling the flow paths of the drilling fluid.
  • the system 100 can include one or more flow-control devices that can stop the flow of the fluid in the drill string and/or the annulus 194.
  • Figure 1A shows an exemplary flow-control device 173 that includes a device 174 that can block the fluid flow within the drill string 121 and a device 175 that blocks can block fluid flow through the annulus 194.
  • the device 173 can be activated when a particular condition occurs to insulate the well above and below the flow-control device 173.
  • the flow-control device 173 may be activated to block fluid flow communication when drilling fluid circulation is stopped so as to isolate the sections above and below the device 173, thereby maintaining the wellbore below the device 173 at or substantially at the pressure condition prior to the stopping of the fluid circulation.
  • the flow-control devices 174, 175 can also be configured to selectively control the flow path of the drilling fluid.
  • the flow- control device 174 in the drill pipe 121 can be configured to direct some or all of the fluid in drill string 121 into the annulus 194.
  • one or both of the flow-control devices 174, 175 can be configured to bypass some or all of the return fluid around the APD device 170.
  • Such an arrangement may be useful, for instance, to assist in lifting cuttings to the surface.
  • the flow-control device 173 may include check-valves, packers and any other suitable device. Such devices may automatically activate upon the occurrence of a particular event or condition.
  • the system 100 also includes downhole devices for processing the cuttings (e.g., reduction of cutting size) and other debris flowing in the annulus 194.
  • a comminution device 176 can be disposed in the annulus 194 upstream of the APD device 170 to reduce the size of entrained cutting and other debris.
  • the comminution device 176 can use known members such as blades, teeth, or rollers to crush, pulverize or otherwise disintegrate cuttings and debris entrained in the fluid flowing in the annulus 194.
  • the comminution device 176 can be operated by an electric motor, a hydraulic motor, by rotation of drill string or other suitable means.
  • the comminution device 176 can also be integrated into the APD device 170. For instance, if a multi-stage turbine is used as the APD device 170, then the stages adjacent the inlet to the turbine can be replaced with blades adapted to cut or shear particles before they pass through the blades of the remaining turbine stages.
  • Sensors Si -n are strategically positioned throughout the system 100 to provide information or data relating to one or more selected parameters of interest (pressure, flow rate, temperature).
  • the downhole devices and sensors Si. n communicate with a controller 180 via a telemetry system (not shown).
  • the controller 180 uses data provided by the sensors Si. n , the controller 180 maintains the wellbore pressure at zone 155 at a selected pressure or range of pressures.
  • the controller 180 maintains the selected pressure by controlling the APD device 170 (e.g., adjusting amount of energy added to the return fluid line) and/or the downhole devices (e.g., adjusting flow rate through a restriction such as a valve).
  • the sensors Si. n provide measurements relating to a variety of drilling parameters, such as fluid pressure, fluid flow rate, rotational speed of pumps and like devices, temperature, weight-on bit, rate of penetration, etc., drilling assembly or BHA parameters, such as vibration, stick slip, RPM, inclination, direction, BHA location, etc. and formation or formation evaluation parameters commonly referred to as measurement-while-drilling parameters such as resistivity, acoustic, nuclear, NMR, etc.
  • One preferred type of sensor is a pressure sensor for measuring pressure at one or more locations. Referring still to Fig.
  • pressure sensor Pi provides pressure data in the BHA
  • sensor P 2 provides pressure data in the annulus
  • pressure sensor P 4 provides pressure data at the surface.
  • Other pressure sensors may be used to provide pressure data at any other desired place in the system 100.
  • the system 100 includes fluid flow sensors such as sensor V that provides measurement of fluid flow at one or more places in the system.
  • the status and condition of equipment as well as parameters relating to ambient conditions (e.g., pressure and other parameters listed above) in the system 100 can be monitored by sensors positioned throughout the system 100: exemplary locations including at the surface (S1), at the APD device 170 (S2), at the wellhead equipment 125 (S3), in the supply fluid (S4), along the tubing 121 (S5), at the well tool 135 (S6), in the return fluid upstream of the APD device 170 (S7), and in the return fluid downstream of the APD device 170 (S8). It should be understood that other locations may also be used for the sensors Si. n .
  • the controller 180 for suitable for drilling operations preferably includes programs for maintaining the wellbore pressure at zone 155 at under-balance condition, at at-balance condition or at over-balanced condition.
  • the controller 180 includes one or more processors that process signals from the various sensors in the drilling assembly and also controls their operation.
  • the data provided by these sensors Si. n and control signals transmitted by the controller 180 to control downhole devices such as devices 173-176 are communicated by a suitable two-way telemetry system (not shown).
  • a separate processor may be used for each sensor or device.
  • Each sensor may also have additional circuitry for its unique operations.
  • the controller 180 which may be either downhole or at the surface, is used herein in the generic sense for simplicity and ease of understanding and not as a limitation because the use and operation of such controllers is known in the art.
  • the controller 180 preferably contains one or more microprocessors or micro-controllers for processing signals and data and for performing control functions, solid state memory units for storing programmed instructions, models (which may be interactive models) and data, and other necessary control circuits.
  • the microprocessors control the operations of the various sensors, provide communication among the downhole sensors and provide two-way data and signal communication between the drilling assembly 30, downhole devices such as devices 173-175 and the surface equipment via the two-way telemetry.
  • the controller 180 can be a hydro-mechanical device that incorporates known mechanisms (valves, biased members, linkages cooperating to actuate tools under, for example, preset conditions).
  • controller 180 For convenience, a single controller 180 is shown. It should be understood, however, that a plurality of controllers 180 can also be used.
  • a downhole controller can be used to collect, process and transmit data to a surface controller, which further processes the data and transmits appropriate control signals downhole.
  • Other variations for dividing data processing tasks and generating control signals can also be used.
  • the controller 180 receives the information regarding a parameter of interest and adjusts one or more downhole devices and/or APD device 170 to provide the desired pressure or range or pressure in the vicinity of the zone of interest 155.
  • the controller 180 can receive pressure information from one or more of the sensors (Si-S n ) in the system 100.
  • the controller 180 may control the APD Device 170 in response to one or more of: pressure, fluid flow, a formation characteristic, a wellbore characteristic and a fluid characteristic, a surface measured parameter or a parameter measured in the drill string.
  • the controller 180 determines the ECD and adjusts the energy input to the APD device 170 to maintain the ECD at a desired or predetermined value or within a desired or predetermined range.
  • the wellbore system 100 thus provides a closed loop system for controlling the ECD in response to one or more parameters of interest during drilling of a wellbore. This system is relatively simple and efficient and can be incorporated into new or existing drilling systems and readily adapted to support other well construction, completion, and work-over activities.
  • the APD Device 170 is shown as a turbine attached to the drill string 121 that operates within the annulus 194.
  • Other embodiments, described in further detail below can include centrifugal pumps, positive displacement pump, jet pumps and other like devices.
  • the APD Device 170 moves in the wellbore 90 along with the drill string 121.
  • the return fluid can flow through the APD Device 170 whether or not the turbine is operating.
  • the APD Device 170 when operated creates a differential pressure thereacross.
  • the system 100 in one embodiment includes a controller 180 that includes a memory and peripherals 184 for controlling the operation of the APD Device 170, the devices 173-176, and/or the bottomhole assembly 135.
  • the controller 180 is shown placed at the surface. It, however, may be located adjacent the APD Device 170, in the BHA 135 or at any other suitable location.
  • the controller 180 controls the APD Device to create a desired amount of ⁇ P across the device, which alters the bottomhole pressure accordingly.
  • the controller 180 may be programmed to activate the flow-control device 173 (or other downhole devices) according to programmed instructions or upon the occurrence of a particular condition.
  • the controller 180 can control the APD Device in response to sensor data regarding a parameter of interest, according to programmed instructions provided to said APD Device, or in response to instructions provided to said APD Device from a remote location.
  • the controller 180 can, thus, operate autonomously or interactively.
  • the controller 180 controls the operation of the APD Device to create a certain pressure differential across the device so as to alter the pressure on the formation or the bottomhole pressure.
  • the controller 180 may be programmed to maintain the wellbore pressure at a value or range of values that provide an under-balance condition, an at-balance condition or an over-balanced condition.
  • the differential pressure may be altered by altering the speed of the APD Device.
  • the bottomhole pressure may be maintained at a preselected value or within a selected range relative to a parameter of interest such as the formation pressure.
  • the controller 180 may receive signals from one or more sensors in the system 100 and in response thereto control the operation of the APD Device to create the desired pressure differential.
  • the controller 180 may contain preprogrammed instructions and autonomously control the APD Device or respond to signals received from another device that may be remotely located from the APD Device.
  • Figure 1B graphically illustrates the ECD control provided by the above-described embodiment of the present invention and references Figure 1A for convenience.
  • Figure 1A shows the APD device 170 at a depth D1 and a representative location in the wellbore in the vicinity of the well tool 30 at a lower depth D2.
  • Figure 1 B provides a depth versus pressure graph having a first curve C1 representative of a pressure gradient before operation of the system 100 and a second curve C2 representative of a pressure gradients during operation of the system 100.
  • Curve C3 represents a theoretical curve wherein the ECD condition is not present; i.e., when the well is static and not circulating and is free of drill cuttings.
  • the system 100 reduces the hydrostatic pressure at depth D1 and thus shifts the pressure gradient as shown by curve C3, which can provide the desired predetermined pressure at depth D2. In most instances, this shift is roughly the pressure drop provided by the APD device 170.
  • Figure 2 shows the drill string after it has moved the distance "d" shown by ti _t 2 . Since the APD Device 170 is attached to the drill string 121, the APD Device 170 also is shown moved by the distance d.
  • an APD Device 170a may be attached to the wellbore in a manner that will allow the drill string 121 to move while the APD Device 170a remains at a fixed location.
  • Figure 3 shows an embodiment wherein the APD Device is attached to the wellbore inside and is operated by a suitable device 172a.
  • the APD device can be attached to a location stationary relative to said drill string such as a casing, a liner, the wellbore annulus, a riser, or other suitable wellbore equipment.
  • the APD Device 170a is preferably installed so that it is in a cased upper section 129.
  • the device 170a is controlled in the manner described with respect to the device 170 (Fig 1A).
  • a positive displacement motor/drive 200 is coupled to a moineau-type pump 220 via a shaft assembly 240.
  • the motor 200 is connected to an upper string section 260 through which drilling fluid is pumped from a surface location.
  • the pump 220 is connected to a lower drill string section 262 on which the bottomhole assembly (not shown) is attached at an end thereof.
  • the motor 200 includes a rotor 202 and a stator 204.
  • the pump 220 includes a rotor 222 and a stator 224.
  • the design of moineau-type pumps and motors are known to one skilled in the art and will not be discussed in further detail.
  • the shaft assembly 240 transmits the power generated by the motor 200 to the pump 220.
  • One preferred shaft assembly 240 includes a motor flex shaft 242 connected to the motor rotor 202, a pump flex shaft 244 connected to the pump rotor 224, and a coupling shaft 246 for joining the first and second shafts 242 and 244.
  • a high-pressure seal 248 is disposed about the coupling shaft 246.
  • the rotors for moineau-type motors/pump are subject to eccentric motion during rotation.
  • the coupling shaft 246 is preferably articulated or formed sufficiently flexible to absorb this eccentric motion.
  • the shafts 242, 244 can be configured to flex to accommodate eccentric motion.
  • a speed or torque converter 252 can be used to convert speed/torque of the motor 200 to a second speed/torque for the pump 220.
  • speed/torque converter it is meant known devices such as variable or fixed ratio mechanical gearboxes, hydrostatic torque converters, and a hydrodynamic converters. It should be understood that any number of arrangements and devices can be used to transfer power, speed, or torque from the motor 200 to the pump 220.
  • the shaft assembly 240 can utilize a single shaft instead of multiple shafts.
  • a comminution device can be used to process entrained cutting in the return fluid before it enters the pump 200.
  • a comminution device ( Figure 1A) can be coupled to the drive 200 or pump 220 and operated thereby.
  • one such comminution device or cutting mill 270 can include a shaft 272 coupled to the pump rotor 224.
  • the shaft 272 can include a conical head or hammer element 274 mounted thereon.
  • the eccentric motion of the pump rotor 224 will cause a corresponding radial motion of the shaft head 274. This radial motion can be used to resize the cuttings between the rotor and a comminution device housing 276.
  • the Figures 4A-D arrangement also includes a supply flow path 290 to carry supply fluid from the device 200 to the lower drill string section 262 and a return flow path 292 to channel return fluid from the casing interior or annulus into and out of the pump 220.
  • the high pressure seal 248 is interposed between the flow paths 290 and 292 to prevent fluid leaks, particularly from the high pressure fluid in the supply flow path 290 into the return flow path 292.
  • the seal 248 can be a high-pressure seal, a hydrodynamic seal or other suitable seal and formed of rubber, an elastomer, metal or composite.
  • bypass devices are provided to allow fluid circulation during tripping of the downhole devices of the system 100 (Fig.
  • Exemplary bypass devices include a circulation bypass 300, motor bypass 310, and a pump bypass 320.
  • the circulation bypass 300 selectively diverts supply fluid into the annulus 194 (Fig. 1A) or casing C interior.
  • the circulation bypass 300 is interposed generally between the upper drill string section 260 and the motor 200.
  • One preferred circulation bypass 300 includes a biased valve member 302 that opens when the flow-rate drops below a predetermined valve. When the valve 302 is open, the supply fluid flows along a channel 304 and exits at ports 306. More generally, the circulation bypass can be configured to actuate upon receiving an actuating signal and/or detecting a predetermined value or range of values relating to a parameter of interest (e.g., flow rate or pressure of supply fluid or operating parameter of the bottomhole assembly).
  • the circulation bypass 300 can be used to facilitate drilling operations and to selective increase the pressure/flow rate of the return fluid.
  • the motor bypass 310 selectively channels conveys fluid around the motor 200.
  • the motor bypass 310 includes a valve 312 and a passage 314 formed through the motor rotor 202.
  • a joint 316 connecting the motor rotor 202 to the first shaft 242 includes suitable passages (not shown) that allow the supply fluid to exit the rotor passage 314 and enter the supply flow path 290.
  • a pump bypass 320 selectively conveys fluid around the pump 220.
  • the pump bypass includes a valve and a passage formed through the pump rotor 222 or housing.
  • the pump bypass 320 can also be configured to function as a particle bypass line for the APD device.
  • the pump bypass can be adapted with known elements such as screens or filters to selectively convey cuttings or particles entrained in the return fluid that are greater than a predetermined size around the APD device.
  • a separate particle bypass can be used in addition to the pump bypass for such a function.
  • a valve (not shown) in a pump housing 225 can divert fluid to a conduit parallel to the pump 220. Such a valve can be configured to open when the flow rate drops below a predetermined value.
  • the bypass device can be a design internal leakage in the pump. That is, the operating point of the pump 220 can be controlled by providing a preset or variable amount of fluid leakage in the pump 220.
  • pressure valves can be positioned in the pump 220 to discharge fluid in the event an overpressure condition or other predetermined condition is detected.
  • annular seal 299 in certain embodiments can be disposed around the APD device to direct the return fluid to flow into the pump 220 (or more generally, the APD device) and to allow a pressure differential across the pump 220.
  • the seal 299 can be a solid or pliant ring member, an expandable packer type element that expands/contracts upon receiving a command signal, or other member that substantially prevents the return fluid from flowing between the pump 220 (or more generally, the APD device) and the casing or wellbore wall.
  • the clearance between the APD device and adjacent wall may be sufficiently small as to not require an annular seal.
  • the motor 200 and pump 220 are positioned in a well bore location such as in a casing C.
  • Drilling fluid (the supply fluid) flowing through the upper drill string section 260 enters the motor 200 and causes the rotor 202 to rotate. This rotation is transferred to the pump rotor 222 by the shaft assembly 240.
  • the respective lobe profiles, size and configuration of the motor 200 and the pump 220 can be varied to provide a selected speed or torque curve at given flow-rates.
  • the supply fluid flows through the supply flow path 290 to the lower drill string section 262, and ultimately the bottomhole assembly (not shown).
  • the return fluid flows up through the wellbore annulus (not shown) and casing C and enters the cutting mill 270 via a inlet 293 for the return flow path 292.
  • the flow goes through the cutting mill 270 and enters the pump 220.
  • the controller 180 (Fig. 1A) can be programmed to control the speed of the motor 200 and thus the operation of the pump 220 (the APD Device in this instance).
  • FIG. 5A-B there is schematically illustrated one arrangement wherein a turbine drive 350 is coupled to a centrifugal-type pump 370 via a shaft assembly 390.
  • the turbine 350 includes stationary and rotating blades 354 and radial bearings 402.
  • the centrifugal-type pump 370 includes a housing 372 and multiple impeller stages 374.
  • the design of turbines and centrifugal pumps are known to one skilled in the art and will not be discussed in further detail.
  • the shaft assembly 390 transmits the power generated by the turbine 350 to the centrifugal pump 370.
  • One preferred shaft assembly 350 includes a turbine shaft 392 connected to the turbine blade assembly 354, a pump shaft 394 connected to the pump impeller stages 374, and a coupling 396 for joining the turbine and pump shafts 392 and 394.
  • the Figure 5A-B arrangement also includes a supply flow path 410 for channeling supply fluid shown by arrows designated 416 and a return flow path 418 to channel return fluid shown by arrows designated 424.
  • the supply flow path 410 includes an inlet 412 directing supply fluid into the turbine 350 and an axial passage 413 that conveys the supply fluid exiting the turbine 350 to an outlet 414.
  • the return flow path 418 includes an inlet 420 that directs return fluid into the centrifugal pump 370 and an outlet 422 that channels the return fluid into the casing C interior or wellbore annulus.
  • a high pressure seal 400 is interposed between the flow paths 410 and 418 to reduce fluid leaks, particularly from the high pressure fluid in the supply flow path 410 into the return flow path 418.
  • a small leakage rate is desired to cool and lubricate the axial and radial bearings.
  • a bypass 426 can be provided to divert supply fluid from the turbine 350.
  • radial and axial forces can be borne by bearing assemblies 402 positioned along the shaft assembly 390.
  • a comminution device 373 is provided to reduce particle size entering the centrifugal pump 370.
  • one of the impeller stages is modified with shearing blades or elements that shear entrained particles to reduce their size.
  • a speed or torque converter 406 can be used to convert a first speed/torque of the motor 350 to a second speed/torque for the centrifugal pump 370. It should be understood that any number of arrangements and devices can be used to transfer power, speed, or torque from the turbine 350 to the pump 370.
  • the shaft assembly 390 can utilize a single shaft instead of multiple shafts.
  • a positive displacement pump need not be matched with only a positive displacement motor, or a centrifugal pump with only a turbine.
  • operational speed or space considerations may lend itself to an arrangement wherein a positive displacement drive can effectively energize a centrifugal pump or a turbine drive energize a positive displacement pump.
  • the present invention is not limited to the above-described arrangements.
  • a positive displacement motor can drive an intermediate device such as an electric motor or hydraulic motor provided with an encapsulated clean hydraulic reservoir. In such an arrangement, the hydraulic motor (or produced electric power) drives the pump.
  • a jet pump can be used.
  • the supply fluid is divided into two streams.
  • the first stream is directed to the BHA.
  • the second stream is accelerated by a nozzle and discharged with high velocity into the annulus, thereby effecting a reduction in annular pressure.
  • Pumps incorporating one or more pistons, such as hammer pumps, may also be suitable for certain applications.
  • an electrical motor can be used to drive and control the APD Device. Varying the speed of the electrical motor will directly control the speed of the rotor in the APD device, and thus the pressure differential across the APD Device.
  • a clutch element can be added to the shaft assembly connecting the drive to the pump to selectively couple and uncouple the drive and pump.
  • a magnetic clutch can be used to engage the drive and the pump. In such an arrangement, the supply fluid and drive and the return fluid and pump can remain separated. The speed/torque can be transferred by a magnetic connection that couples the drive and pump elements, which are separated by a tubular element (e.g., drill string).
  • centrifugal pump that is attached to the drill string.
  • the pump can include a multi-stage impeller and can be driven by a hydraulic power unit, such as a motor. This motor may be operated by the drilling fluid or by any other suitable manner.
  • APD Device that is fixed to the drill string, which is operated by the drill string rotation.
  • a number of impellers are attached to the drill string. The rotation of the drill string rotates the impeller that creates a differential pressure across the device.
  • the teachings of the present invention can be advantageously applied to manage wellbore pressure throughout the well construction process.
  • formations can have a narrow "window" within which wellbore pressure must be maintained to prevent a kick or damage to the formation.
  • the lower pressure limit is generally the pore pressure of the formation and the upper limit is the fracture pressure of the formation.
  • Wellbore pressure should be maintained within this "window" both when the formation is being drilled and during periods when drilling has been interrupted. Instances where drilling is interrupted include periods where joints are added to the drill string and when the drill string is tripped into or out of the wellbore.
  • embodiments of the present invention can be used to control pressure in such situations.
  • FIG. 6 there is shown a graph illustrating changes in wellbore pressure during such a procedure.
  • the x-axis represents time and the y-axis represents dynamic pressure loss.
  • a zero value for dynamic pressure loss is labeled with numeral 0.
  • a line 700 generally represents wellbore pressure associated with a conventional drilling system.
  • Interval 702 represent a time period when drilling is halted
  • interval 704 represent a time period when drilling is occurring
  • interval 706 represents transient conditions.
  • wellbore pressure at interval 702 is generally the hydrostatic pressure of the mud column.
  • a dynamic pressure loss occurs due to fluid circulation, which manifests itself as an increase in wellbore pressure. While the interval 706 is shown as smooth transitions between the upper and lower pressure values, it should be understood that the cycling of mud pumps and other factors can cause spikes in pressure. As can be seen, with conventional drilling systems, wellbore pressure periodically varies between an upper and lower pressure value due to dynamic pressure losses.
  • a line 710 represents the pressure associated with a drilling system utilizing an APD Device (e.g., the APD Device 170 of Fig. 1A).
  • the line 710 is shown offset from the lower pressure values of line 700 merely for clarity.
  • interval 712 represents a time period when drilling is halted and interval 714 represents a time period when drilling is occurring. Intervals of transient conditions can exist but have been omitted for simplicity. At interval 712, there is no fluid circulation and, therefore, no dynamic pressure loss.
  • wellbore pressure at interval 712 is generally the hydrostatic pressure of the mud column.
  • a pressure loss normally occurs due to fluid circulation, which manifests itself as an increase in wellbore pressure.
  • the APD Device reduces the dynamic pressure loss at interval 704 of line 700.
  • the pressure differential generated by the APD Device is shown as generally equaling the dynamic pressure loss.
  • the pressure differential can be selected to be a fraction or a multiple of the dynamic pressure loss.
  • the APD Device can reduce the magnitude of the pressure changes, which can lead to a more benign pressure condition in the wellbore when fluid circulation is periodically halted.
  • the utility of the present invention extends also to applications where circulation continues even though drilling is halted.
  • a conventional drilling rig 730 utilizing a continuous circulation system 732 The rig 730 includes known equipment such as a top drive 734, a blowout preventer (BOP) stack 736, and a fluid circulation system 738, which includes known equipment such as a pump, mud pit and suitable conduits.
  • a drill string 740 suspended from the rig 730 drills a wellbore 742 in a formation 736.
  • the continuous circulation system 732 includes a coupler 733 that is connected to the top drive 734 and drill string 740.
  • the top drive 734 rotates the drill string 740 while the fluid circulation system 738 pumps drilling fluid into the wellbore 742 via the top drive 734 and drill string 740.
  • the coupler 733 maintains fluid circulation through the drill string 740 and to the wellbore 742 even when the top drive 734 is uncoupled from the drill string 740.
  • the coupler 733 can include suitable rams and isolation chambers that direct drilling fluid into the drill string while one or more tubular joints are made up to the drill string.
  • One suitable coupler is discussed in "Continuous Circulation Drilling", OTC 14269, J.W. Jenner, et al., which is hereby incorporated by reference for all purposes.
  • the continuous circulation system 732 reduces or eliminates the instances where drilling fluid ceases to flow in the wellbore 742.
  • wellbore pressure does not normally drop to hydrostatic pressure when the continuous circulation system 732 is in operation.
  • the coupler 733 is merely representative of devices and equipment that convey fluid into the wellbore while making a connection to the drill string or while tripping the drill string.
  • the teachings of the present invention can be advantageously utilized with any device or system that can convey fluid into the wellbore during activities such as tripping and connections interrupt drilling.
  • the term "continuous circulation system” should be understood generically to refer to one or more devices that can be operated to convey fluid and not any particular device or system.
  • FIG. 8 there is shown a graph illustrating the wellbore pressure changes associated with the Fig. 7 system.
  • the x-axis represents time and the y-axis represents dynamic pressure loss.
  • a line 750 represents pressure for the Fig. 7 drilling system.
  • Interval 752 represent a time period when drilling is halted and interval 754 represent a time period when drilling is occurring.
  • interval 754 represent a time period when drilling is occurring.
  • a dynamic pressure loss occurs due to fluid circulation, which manifests itself as an increase in wellbore pressure relative to hydrostatic pressure.
  • the wellbore pressure is generally the hydrostatic pressure plus ECD for the Fig. 7 system.
  • wellbore pressure should be maintained between the pore pressure and the fracture pressure.
  • the wellbore pressure associated with operation of the continuous circulation system 732 should remain above pore pressure even if fluid circulation is interrupted. That is, the value of the hydrostatic pressure alone, without dynamic pressure loss, should be greater than pore pressure to ensure formation fluids do not flow into the wellbore since dynamic pressure loss disappears when circulation stops.
  • a conventional circulation system could utilize a drilling fluid having a high enough mud weight to provide a hydrostatic pressure above pore pressure.
  • dynamic pressure loss is additive to hydrostatic pressure.
  • dynamic pressure losses could cause wellbore pressure to approach or exceed the fracture pressure of the formation.
  • FIG. 7 there is shown an APD Device 760 positioned in the wellbore in conjunction with the continuous circulation system 732.
  • the APD Device 760 creates a pressure differential in the wellbore in a manner previously discussed.
  • this pressure differential reduces dynamic pressure losses and thereby shifts the line 750 to dashed line 770. It should be appreciated that this shift can assist in keeping wellbore pressure below the fracture pressure of the formation.
  • wellbore pressure can be so maintained even when using a drilling fluid having a mud weight that provides a hydrostatic pressure greater than pore pressure.
  • hydrostatic pressure which is higher than pore pressure.
  • a surface flow modulation or restriction device 780 can be used to control wellbore pressure by controlling the flow of fluid out of the wellbore 742.
  • the flow restriction device 780 which can be a choke or valve, can be actuated to modulate flow of drilling fluid out of the annulus of the wellbore 742 and thereby alter wellbore pressure.
  • a restriction of flow can cause a backpressure in the annulus of the wellbore 742 that can increase wellbore pressure. This backpressure can in effect reduce the magnitude of the pressure differential caused by the APD Device 760.
  • the APD Device 760 can be operated to provide a generally fixed pressure differential.
  • the flow restriction device 780 can be modulated as desired to increase backpressure and thereby set the wellbore pressure. It should be thus appreciated that any device that can control flow out of the wellbore can be suitable for such a purpose.
  • the utility of the APD Device in conjunction with a continuous circulation system can also be applied to instances such as tripping of a drill string into or out of a wellbore.
  • the transient interval 706 can include pressure spikes that temporarily and significantly vary wellbore pressure; e.g., surge effects can increase wellbore pressure whereas swab effect can decrease wellbore pressure. Operation of the APD Device during such transient conditions can mitigate such effects by appropriately controlling wellbore pressure.

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Abstract

L'invention porte sur un dispositif de contrôle actif de la pression ('active pressure control device' ou APD) qui permet d'exercer pression différentielle dans un puits de forage afin de réguler la perte de pression dynamique tandis qu'un fluide de forage circule en continu dans le puits. Selon l'invention, un système de circulation continue fait circuler le fluide tant au cours du forage du puits qu'à l'arrêt du forage. L'utilisation du dispositif APD permet de réguler la pression du puits de forage pendant la circulation en continu sans modifier sensiblement la densité du fluide. Le dispositif de l'invention permet de maintenir la pression du puits sous la pression combinée entraînée par le poids du fluide et par les pertes de pression créées par la circulation du fluide dans le puits de forage, de maintenir le puits de forage dans un état de pression d'équilibre ou proche de la pression d'équilibre, de maintenir le puits dans un état de sous-pression, de réduire l'effet de pistonnement dans le puits et/ou de réduire l'effet de saute de pression dans le puits. Un dispositif limiteur de débit qui crée une contrepression dans l'espace annulaire du puits permet un contrôle en surface de la pression dans le puits de forage.
PCT/US2006/023495 2005-06-17 2006-06-16 Systeme et procede de controle actif de la pression fond de trou au moyen d'un systeme a circulation continue WO2006138565A1 (fr)

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GB0724939A GB2441927B (en) 2005-06-17 2006-06-16 Active controlled bottomhole pressure system and method with continuous circulation system
CA002612111A CA2612111A1 (fr) 2005-06-17 2006-06-16 Systeme et procede de controle actif de la pression fond de trou au moyen d'un systeme a circulation continue
NO20076490A NO343598B1 (no) 2005-06-17 2007-12-18 Aktivt styrt bunnhullstrykksystem og fremgangsmåte med kontinuerlig sirkulasjonssystem

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US69179205P 2005-06-17 2005-06-17
US60/691,792 2005-06-17

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US8201628B2 (en) 2010-04-27 2012-06-19 Halliburton Energy Services, Inc. Wellbore pressure control with segregated fluid columns
US8281875B2 (en) 2008-12-19 2012-10-09 Halliburton Energy Services, Inc. Pressure and flow control in drilling operations
US8584749B2 (en) 2010-12-17 2013-11-19 Exxonmobil Upstream Research Company Systems and methods for dual reinjection
US8666717B2 (en) 2008-11-20 2014-03-04 Exxonmobil Upstream Resarch Company Sand and fluid production and injection modeling methods
US8739863B2 (en) 2010-11-20 2014-06-03 Halliburton Energy Services, Inc. Remote operation of a rotating control device bearing clamp
US8776894B2 (en) 2006-11-07 2014-07-15 Halliburton Energy Services, Inc. Offshore universal riser system
US8820405B2 (en) 2010-04-27 2014-09-02 Halliburton Energy Services, Inc. Segregating flowable materials in a well
US8833488B2 (en) 2011-04-08 2014-09-16 Halliburton Energy Services, Inc. Automatic standpipe pressure control in drilling
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US9163473B2 (en) 2010-11-20 2015-10-20 Halliburton Energy Services, Inc. Remote operation of a rotating control device bearing clamp and safety latch
US9169700B2 (en) 2010-02-25 2015-10-27 Halliburton Energy Services, Inc. Pressure control device with remote orientation relative to a rig
CN105134111A (zh) * 2015-08-25 2015-12-09 宝鸡石油机械有限责任公司 一种多功能井眼清洗工具
US9567843B2 (en) 2009-07-30 2017-02-14 Halliburton Energy Services, Inc. Well drilling methods with event detection
US9605507B2 (en) 2011-09-08 2017-03-28 Halliburton Energy Services, Inc. High temperature drilling with lower temperature rated tools
US9823373B2 (en) 2012-11-08 2017-11-21 Halliburton Energy Services, Inc. Acoustic telemetry with distributed acoustic sensing system
WO2022132158A1 (fr) * 2020-12-16 2022-06-23 Halliburton Energy Services, Inc. Système et procédé servant à effectuer un forage en sous-pression

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US20240044219A1 (en) * 2022-08-03 2024-02-08 Weatherford Technology Holdings, Llc Reduction of equivalent circulating density in well operations

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US8881831B2 (en) 2006-11-07 2014-11-11 Halliburton Energy Services, Inc. Offshore universal riser system
US9376870B2 (en) 2006-11-07 2016-06-28 Halliburton Energy Services, Inc. Offshore universal riser system
US9157285B2 (en) 2006-11-07 2015-10-13 Halliburton Energy Services, Inc. Offshore drilling method
US9127511B2 (en) 2006-11-07 2015-09-08 Halliburton Energy Services, Inc. Offshore universal riser system
US9127512B2 (en) 2006-11-07 2015-09-08 Halliburton Energy Services, Inc. Offshore drilling method
US9085940B2 (en) 2006-11-07 2015-07-21 Halliburton Energy Services, Inc. Offshore universal riser system
US8776894B2 (en) 2006-11-07 2014-07-15 Halliburton Energy Services, Inc. Offshore universal riser system
US9051790B2 (en) 2006-11-07 2015-06-09 Halliburton Energy Services, Inc. Offshore drilling method
US8887814B2 (en) 2006-11-07 2014-11-18 Halliburton Energy Services, Inc. Offshore universal riser system
WO2009065581A1 (fr) * 2007-11-22 2009-05-28 Services Petroliers Schlumberger Dispositif de déviation de flux pour forage
US8666717B2 (en) 2008-11-20 2014-03-04 Exxonmobil Upstream Resarch Company Sand and fluid production and injection modeling methods
US8281875B2 (en) 2008-12-19 2012-10-09 Halliburton Energy Services, Inc. Pressure and flow control in drilling operations
US9567843B2 (en) 2009-07-30 2017-02-14 Halliburton Energy Services, Inc. Well drilling methods with event detection
US8397836B2 (en) 2009-12-15 2013-03-19 Halliburton Energy Services, Inc. Pressure and flow control in drilling operations
US8286730B2 (en) 2009-12-15 2012-10-16 Halliburton Energy Services, Inc. Pressure and flow control in drilling operations
US9169700B2 (en) 2010-02-25 2015-10-27 Halliburton Energy Services, Inc. Pressure control device with remote orientation relative to a rig
US8261826B2 (en) 2010-04-27 2012-09-11 Halliburton Energy Services, Inc. Wellbore pressure control with segregated fluid columns
US8820405B2 (en) 2010-04-27 2014-09-02 Halliburton Energy Services, Inc. Segregating flowable materials in a well
US8201628B2 (en) 2010-04-27 2012-06-19 Halliburton Energy Services, Inc. Wellbore pressure control with segregated fluid columns
US8739863B2 (en) 2010-11-20 2014-06-03 Halliburton Energy Services, Inc. Remote operation of a rotating control device bearing clamp
US9163473B2 (en) 2010-11-20 2015-10-20 Halliburton Energy Services, Inc. Remote operation of a rotating control device bearing clamp and safety latch
US10145199B2 (en) 2010-11-20 2018-12-04 Halliburton Energy Services, Inc. Remote operation of a rotating control device bearing clamp and safety latch
US8584749B2 (en) 2010-12-17 2013-11-19 Exxonmobil Upstream Research Company Systems and methods for dual reinjection
US8833488B2 (en) 2011-04-08 2014-09-16 Halliburton Energy Services, Inc. Automatic standpipe pressure control in drilling
US9080407B2 (en) 2011-05-09 2015-07-14 Halliburton Energy Services, Inc. Pressure and flow control in drilling operations
US9605507B2 (en) 2011-09-08 2017-03-28 Halliburton Energy Services, Inc. High temperature drilling with lower temperature rated tools
US10233708B2 (en) 2012-04-10 2019-03-19 Halliburton Energy Services, Inc. Pressure and flow control in drilling operations
US9823373B2 (en) 2012-11-08 2017-11-21 Halliburton Energy Services, Inc. Acoustic telemetry with distributed acoustic sensing system
CN105134111A (zh) * 2015-08-25 2015-12-09 宝鸡石油机械有限责任公司 一种多功能井眼清洗工具
WO2022132158A1 (fr) * 2020-12-16 2022-06-23 Halliburton Energy Services, Inc. Système et procédé servant à effectuer un forage en sous-pression
GB2615023A (en) * 2020-12-16 2023-07-26 Halliburton Energy Services Inc System and method to conduct underbalanced drilling
US11719058B2 (en) 2020-12-16 2023-08-08 Halliburton Energy Services, Inc. System and method to conduct underbalanced drilling
GB2615023B (en) * 2020-12-16 2024-09-04 Halliburton Energy Services Inc System and method to conduct underbalanced drilling

Also Published As

Publication number Publication date
GB2470859A (en) 2010-12-08
CA2612111A1 (fr) 2006-12-28
GB201015440D0 (en) 2010-10-27
NO343598B1 (no) 2019-04-08
NO20076490L (no) 2008-03-11
GB2441927A (en) 2008-03-19
GB2441927B (en) 2011-02-09
GB0724939D0 (en) 2008-01-30

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