EP2053196A1 - Système et procédé de contrôle de la pression dans un puits - Google Patents

Système et procédé de contrôle de la pression dans un puits Download PDF

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Publication number
EP2053196A1
EP2053196A1 EP07119135A EP07119135A EP2053196A1 EP 2053196 A1 EP2053196 A1 EP 2053196A1 EP 07119135 A EP07119135 A EP 07119135A EP 07119135 A EP07119135 A EP 07119135A EP 2053196 A1 EP2053196 A1 EP 2053196A1
Authority
EP
European Patent Office
Prior art keywords
pressure
tubular element
control system
seal
sleeve
Prior art date
Legal status (The legal status 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 status listed.)
Withdrawn
Application number
EP07119135A
Other languages
German (de)
English (en)
Inventor
Egbert Jan Van Riet
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Shell Internationale Research Maatschappij BV
Original Assignee
Shell Internationale Research Maatschappij BV
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 Shell Internationale Research Maatschappij BV filed Critical Shell Internationale Research Maatschappij BV
Priority to EP07119135A priority Critical patent/EP2053196A1/fr
Publication of EP2053196A1 publication Critical patent/EP2053196A1/fr
Withdrawn legal-status Critical Current

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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
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/02—Surface sealing or packing
    • E21B33/08—Wipers; Oil savers
    • E21B33/085—Rotatable packing means, e.g. rotating blow-out preventers
    • 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
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/10—Sealing or packing boreholes or wells in the borehole
    • E21B33/12—Packers; Plugs
    • E21B33/127—Packers; Plugs with inflatable sleeve
    • E21B33/1277—Packers; Plugs with inflatable sleeve characterised by the construction or fixation of the sleeve
    • 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
    • E21B34/00—Valve arrangements for boreholes or wells
    • E21B34/06—Valve arrangements for boreholes or wells in wells
    • 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
    • E21B34/00—Valve arrangements for boreholes or wells
    • E21B34/06—Valve arrangements for boreholes or wells in wells
    • E21B34/10—Valve arrangements for boreholes or wells in wells operated by control fluid supplied from outside the borehole
    • 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
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/12—Methods or apparatus for controlling the flow of the obtained fluid to or in wells
    • 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
    • E21B47/00—Survey of boreholes or wells
    • E21B47/06—Measuring temperature or pressure

Definitions

  • the present invention relates to a pressure control system for controlling the pressure in a well bore formed in a subsurface.
  • the invention also relates to a method of controlling the pressure in a well bore formed in a subsurface.
  • the exploration and production of hydrocarbons from subsurface hydrocarbon-bearing formations requires a method and system to reach and extract the hydrocarbons from the formation. Reaching the formations is accomplished by drilling a borehole in the earth (i.e. the subsurface) to a depth adjacent the formation. Drilling a borehole is typically done by a drilling rig. For instance, if the drilling is land-based, it supports a drill bit that is rotatably mounted on the end of a drill string. A fluid comprised of a base fluid, typically water and oil, is pumped down the drill string and exits through the rotating drill bit. The fluid then circulates back up the annulus formed between the borehole wall and the drill bit, taking with it the cuttings from the drill bit and clearing the borehole.
  • a base fluid typically water and oil
  • tubing or casing is inserted in the borehole to form a well bore and the annular space between this tubing or casing and the subsurface is optionally filled with cement.
  • the tubing or casing strengthens the borehole, while the cement forms a seal to prevent fluid flow outside the casing.
  • Wells may be drilled in an overbalanced condition.
  • the fluid used in the overbalanced condition has a hydrostatic fluid pressure in excess of the formation fluid pressure, thereby preventing formation fluids from entering into the borehole.
  • the fluid pressure is higher than the formation pressure, some fluid will invade the formations adjacent the well bore. This may cause damage to the formations, adversely affecting hydrocarbon production during the lifecycle of the well.
  • wells may be drilled in an underbalanced condition, wherein the wellbore fluid is at a pressure lower than the natural pressure of the formation fluids.
  • underbalanced wells must be drilled through a pressure control device, for instance a rotating control head (RCH) on top of a blow out preventer (BOP) and a choke manifold provided at the surface.
  • the rotating control head permits a tubular drill string to be rotated and lowered there through while retaining a pressure seal around the drill string.
  • Running a drill string or a tool string in and out of a pressurized wellbore is often difficult.
  • a lubricator is used, possibly in combination with snubbing equipment for running the string at a high pressure into the wellbore or stripping equipment for stripping the string, or the well is brought to an overbalanced condition allowing the string to be tripped conventionally to the surface. Both these processes are time consuming and expensive.
  • the downhole deployment valve is located within the tubing or casing and is operated remotely through hydraulic control lines running from the valve to the surface.
  • the downhole deployment valve is used to temporarily isolate a lower part of the wellbore from an upper part thereof.
  • the pressure inside the lower part of the wellbore i.e. essentially the formation pressure, may be isolated from the upper part, wherein the pressure may be reduced considerably, for instance relieved to atmospheric pressure.
  • a drill string or tool string present in the upper part of the wellbore may then be easily removed from the wellbore and another string may be easily run into it.
  • the downhole deployment valve has a downward opening flapper design. Controlled by a hydraulic line the flapper may be moved in downward direction to open the passage through the well bore and in an upward direction to close the same.
  • flapper valve design There is a number of disadvantages associated with this known flapper valve design. First of all, the flapper valve can only hold a relatively low pressure difference from the top down. With an increasing pressure difference this may eventually result in erratic opening of the valve, causing the isolation of the well bore part above the valve from the remaining part of the wellbore be compromised. In order to safeguard the proper functioning of a typical flapper valve, the pressure difference should be kept relatively low.
  • the flapper type of downhole deployment valve is furthermore susceptible to damage of the sealing are and to obstruction by solids. Solids or other substances sticking to the wall of the well or to the valve itself may (partially) block the valve when it is moved from the open to a closed position. In this case the valve will not seal off the upper part of the wellbore, effectively creating a failure of the valve which can potentially lead to a dangerous pressure increase.
  • the deployment valve is also vulnerably to falling objects. For instance, an object accidentally dropped onto the valve that is closed during running a drill string or tool string out of the wellbore, may cause the valve to (partially) open. The pressure below the valve then bypasses the valve and either eject the dropped object or create a potentially dangerous pressure increase at the surface.
  • a further drawback is that it might prove to be impossible to open the flapper valve in case of an excessive pressure build-up below the valve. More generally, it is difficult to repair or to even remove the valve in case of malfunction of the valve in closed position.
  • the known flapper valves cannot be closed when a drill string or tool string is present inside the well bore at the location of the valve.
  • the string has to be tripped first to a position above the valve and only then the valve may be closed. Under certain circumstances this may slow down the drilling process considerably.
  • a pressure control system for controlling the pressure in a well bore formed in a subsurface comprising:
  • the volume of the pressure seal When the pressurization chamber is pressurized, the volume of the pressure seal is caused to increase and to gradually reduce the area available for the fluid to flow. If the pressure inside the seal is further increased, the flow path inside the tubing may even become blocked entirely. On the other hand, when the chamber is depressurized, the volume of the pressure seal is caused to decrease again so that the area available for the fluid to flow is increased and the pressure drop across the seal is reduced. If the pressure in the seal is further (completely) reduced, the fluid may even flow substantially uninterrupted along the pressure seal and the pressure drop across the seal has minimal value.
  • the flexible sleeve of the pressure seal is arranged along the inner circumference of the tubular element.
  • the sleeve may be extend along one or more parts of the inner circumference, but when it extends along substantially the entire length of the inner circumference of the tubing, a more uniform distribution of the fluid flow may be achieved.
  • the sealing characteristics may be improved, especially when the flow path is to be obstructed completely.
  • the tubular element comprises an upper support for attachment of the upper portion of the sleeve and a bottom support for attachment of the lower portion of the sleeve to the inner surface of the tubular element.
  • the supports keep the flexible sleeve at the desired position.
  • the upper and lower support suffice to define the pressurization chamber between the inner surface of the casing and the inner surface of the sleeve.
  • the pressure control system comprises control means being operative so as to control the pressure drop across the pressure seal by applying a predefined hydraulic pressure in the pressure chamber.
  • the pressure drop across the pressure seal may take any value between a maximum value when the flow path is closed completely and a minimum value when the flow path is open.
  • the pressure seal having a flexible sleeve makes it possible to use the seal also when equipment, such as a pipe of a drill string or a tool string, is present at the location of the seal. In this situation the flow path is defined between the outer surface of this equipment and the inner surface of the tubular element.
  • the flow path which usually defines an annular flow area, may be blocked or unblocked by pressurizing or depressurizing the flexible sleeve of the pressure seal.
  • the sleeve is an elastic sleeve, preferably made of (reinforced) rubber.
  • suitable materials include Kevlar or other high-strength flexible materials.
  • One important application of the pressure control system according to the present invention relates to downhole pressure control, wherein the tubular element is arranged in the subsurface within a well bore and the pressure seal is positioned at a predefined depth below the surface.
  • the pressure control system is used as a seal in a rotating control head at the surface instead of a Dynamic Annular Pressure Control (DAPC) choke manifold by controlling the pressure between the sleeve and allowing fluid (including liquid, gas and/or mud) flow to pass between the drill string and the sleeve.
  • DAPC Dynamic Annular Pressure Control
  • a method of controlling the pressure in a well bore formed in a subsurface comprising:
  • the drilling system 1 comprises of a drilling rig that is used to support drilling operations and numerous components used on a rig to accomplish the drilling operation. Many of the components are not shown for ease of description.
  • the borehole 8 has already been partially drilled and a tubular element has already been arranged in the borehole.
  • the tubular element comprises a fixed casing 4, that has been set and cemented in the borehole 8. In other embodiments (not shown) the tubular element is retrievable.
  • a drill string has been deployed, the drill string including a drill pipe 14 supporting a bottom hole assembly (BHA) 3 that includes a drill bit 13.
  • the drill bit 13 is drilling in the subsurface S and extends through well bore formation 21 into a reservoir formation 22.
  • the well may be drilled underbalanced so that, due to the downhole formation pressure, formation fluids may flow through the annular space 25 between the drill pipe 14 and the casing 4 towards the upper portion of the wellbore and even may reach the surface equipment.
  • the well may also be drilled overbalanced so that fluids pumped down the drill string, exiting from the bottom hole assembly 3 and returning to the surface, also through the annular space between drill pipe 14 and casing 4. In both situations fluid may flow from the lower part of the casing to the upper part and even to the surface (direction P 1 , figure 2 ).
  • the pressure may be controlled at the surface by a blow out preventer (BOP) 30, optionally including a RCH, flow lines 31 and a backpressure system 32.
  • BOP blow out preventer
  • the rotating blow out preventer 30 seals around the pipe 14 as it moves in and out the well bore 8, isolating the pressure, but still permitting drill string rotation.
  • the pressure may also be controlled downhole at the position of a pressure control valve 5.
  • Figures 2 and 3 show the pressure control valve 5 in more detail.
  • Figure 2 shows an upper support 10 and a lower support 11 to which respectively the upper and lower ends of an elastic, rubber sleeve element 12 are attached.
  • the supports 10 and 11 and the rubber sleeve 12 extend along the entire inner circumference of the casing 4 and the sleeve defines an annulus, extending concentrically with the tubular element.
  • a space is defined (hereafter called the pressurisation chamber 37), that may be pressurized or depressurized through a hydraulic pressurisation line 39 and pressurisation control device 41.
  • the pressurisation line 39 is connected to a hydraulic system 18 arranged at the surface, as schematically shown in figure 1 .
  • the hydraulic system 18 and pressurisation control device 41 control the flow (direction P 2 ) of hydraulic fluid to and from (direction P 3 ) the pressurisation chamber 37.
  • Figure 2 shows the pressure valve in the fully opened position.
  • the pressure inside the chamber increases, causing the volume of the elastic sleeve 12 to increase (direction P 4 in figure 2 ).
  • An increase of the volume of the elastic sleeve 12 brings about a corresponding reduction of the space 25 between the sleeve and the drill pipe 14. The result is an increasing pressure drop across the pressure valve 5.
  • the volume of sleeve 12 is increased further, the sleeve will eventually seal off the flow path between the sleeve and the drill pipe 14.
  • the situation wherein the pressure valve is completely closed is shown in figure 3 .
  • valve 5 In figures 4 and 5 these are shown wherein no drill string or other equipment is present at the location of the pressure valve 5. For instance, when the drill pipe 14 is to be removed for maintenance reasons, the pipe 14 is pulled up. Once the bit 13 of the drill string is located above the pressure valve 5, the valve can be shut in order to close the open hole section. Valve 5 is shut by pressurizing the pressurisation chamber 37 to a sufficient extent. In the closed (shut) state, the valve seals off the open hole section in a " drop tight' manner.
  • the pressure inside the casing 4 and above the pressure seal 5 can then be bled off and the drill pipe 14 may be removed safely from the casing 4.
  • the drill string may then be run back into the casing 4 to a position just above the pressure seal 5.
  • the upper portion of the casing i.e. the portion above the pressure seal 5 is pressurized again prior to opening the pressure seal 5 again so as to equalize the pressures above and below the valve. This may be accomplished by slowly opening the pressure seal so that the pressure equalisation takes place in a controlled manner.
  • the system comprises a pressure sensor 40 provided in the hydraulic control line at the surface.
  • a pressure sensor 40 provided in the hydraulic control line at the surface.
  • FIG 6 another embodiment of the pressure control system in accordance with the present invention is shown.
  • This embodiment relates to a rotating control head (RCH) pressure control system arranged at the surface.
  • RCH rotating control head
  • the drilling process requires the use of a drilling fluid 36, which is stored in a storage (not shown).
  • the storage is in fluid communication with one or more mud pumps 35 which pump the drilling fluid 36 through a conduit connected to the last joint of the drill string (drill pipe 14) that passes through a RCH and BOP (BOP) 30.
  • a blow out preventer as such is known in the art and a detailed description can be omitted here.
  • the blow out preventer 30 provides for a seal around the drill pipe 14, isolating the pressure, but still permitting drill string rotation and axial movement.
  • the fluid 36 is pumped down (P 5 ) through the drill string 14',14 and the bottom hole assembly (BHA) 3 and exits the drill bit 13, where it circulates the cuttings away from the bit 13 and returns them up the open hole annulus and the annulus 25 formed between the drill pipe 14 and casing 4 (direction P 6 ). The fluid then returns to the surface through annulus 25 formed between drill pipe 14 and casing 4'(direction P 7 ).
  • a typical backpressure system 32 comprises a backpressure pump and a dynamic annular pressure control (DAPC) choke manifold.
  • DAPC dynamic annular pressure control
  • the backpressure system 32 may add backpressure to the pressure in the annulus 25. In this way the annular pressure can be controlled to some extent.
  • DAPC dynamic annular pressure control
  • FIG. 6 shows an example of a blow out preventer 30 equipped with a pressure seal in accordance with the present invention.
  • a typical blowout preventer (BOP) encases the wellbore and includes one or more valves that may be closed if uncontrolled inflow of formation fluids occurs. By closing this valve, the drilling crew can prevent uncontrolled fluid and/or pressure release, thus maintaining control of the well.
  • blowout preventers come in two varieties.
  • a ram blowout preventer utilizes two horizontally opposed hydraulic rams that either close around the drill string or shear through the drill string.
  • An annular blowout preventer (also known as a spherical blowout preventer) utilizes a hemispherical piece of rubber reinforced with steel. Unlike a ram BOP which closes with a sharp horizontal motion, an annular BOP closes around the drill string in a smooth simultaneous upward and inward motion.
  • a blow out preventer has two or more ram type preventers and one annular type preventer. The ram type and annular type preventers are not shown in figure 6 for ease of description.
  • the diverter is omitted and the returning fluid is guided upward through the flow space between the casing 4'and the drill pipe 14. After having passed a pressure valve 27 to be described later, the fluid is discharged (direction P 8 ) through a discharge conduit 38 to the storage mentioned earlier.
  • the pressure valve 27 is provided for controlling the pressure drop from the annulus 25 to the conduit 38 and comprises an elastic sleeve 28 attached to the inner side of casing 4'. Between the material of the sleeve 28 and the inner side of the casing 4' a pressurization chamber 29 is defined.
  • the chamber 29 may be pressurized or depressurized using one or more hydraulic lines 49 that are in fluid communication with the pressurization chamber 29, and a hydraulic pressure control unit 24.
  • the pressure inside the wellbore during circulation can be controlled by applying a controlled pressure outside the rubber sleeve and allowing fluid (mud) flow from the well through the valve at the same time.
  • Another advantage is that due to the fluid film between the rubber sleeve and the drill string or drill pipe, wear can be relatively low.
  • the downhole deployment valve is part of a fixed casing string.
  • the downhole deployment valve may be part of a retrievable workstring which is not cemented in place.
  • the tubular element, also simply referred to as the " tubular" containing the valve can be removed after completion of the drilling operation.
  • the pressure control system may also be used in horizontal wells or, more generally, may be positioned at any borehole angle.
  • more than one pressure seal may be used and if various pressure seals are used, they may be operated differently.

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EP07119135A 2007-10-24 2007-10-24 Système et procédé de contrôle de la pression dans un puits Withdrawn EP2053196A1 (fr)

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Cited By (17)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US8033335B2 (en) 2006-11-07 2011-10-11 Halliburton Energy Services, Inc. Offshore universal riser system
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
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
WO2015094146A1 (fr) * 2013-12-16 2015-06-25 Halliburton Energy Services, Inc. Étagement de pression pour ensemble d'empilement de têtes de puits
US9080407B2 (en) 2011-05-09 2015-07-14 Halliburton Energy Services, Inc. Pressure and flow control in drilling operations
WO2015042408A3 (fr) * 2013-09-20 2015-10-08 Weatherford/Lamb, Inc. Utilisation d'un clapet d'isolement de fond de trou pour détecter une pression d'espace annulaire
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
US9447647B2 (en) 2011-11-08 2016-09-20 Halliburton Energy Services, Inc. Preemptive setpoint pressure offset for flow diversion in drilling operations
US9605507B2 (en) 2011-09-08 2017-03-28 Halliburton Energy Services, Inc. High temperature drilling with lower temperature rated tools
GB2544872A (en) * 2015-10-12 2017-05-31 Schlumberger Technology Bv Debris tolerant flexible element valve
CN107327285A (zh) * 2017-08-16 2017-11-07 中国石油大学(华东) 气井套管环空密封完整性失效预防装置及预防方法
US9957775B2 (en) 2011-03-01 2018-05-01 Conocophillips Company Well plug and abandonment choke insert
US10087713B2 (en) 2014-10-01 2018-10-02 Exxonmobil Upstream Research Company Internal subsurface safety valve for rotating downhole pumps
US10787900B2 (en) 2013-11-26 2020-09-29 Weatherford Technology Holdings, Llc Differential pressure indicator for downhole isolation valve

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US2843349A (en) * 1954-01-04 1958-07-15 Meyer Otto Pressure fluid operated blowout preventer
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US20020027002A1 (en) * 1996-04-01 2002-03-07 Carmody Michael A. Downhole flow control devices
US20050189119A1 (en) * 2004-02-27 2005-09-01 Ashmin Lc Inflatable sealing assembly and method for sealing off an inside of a flow carrier
EP1627986A1 (fr) * 2004-08-19 2006-02-22 Sunstone Corporation Obturateur anti-éruption rotatif

Patent Citations (6)

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US2843349A (en) * 1954-01-04 1958-07-15 Meyer Otto Pressure fluid operated blowout preventer
US3494588A (en) * 1965-09-29 1970-02-10 Schlumberger Technology Corp Flexible sleeve-element valve
US20020027002A1 (en) * 1996-04-01 2002-03-07 Carmody Michael A. Downhole flow control devices
GB2342665A (en) * 1998-10-13 2000-04-19 Mark Buyers Production optimisation tool for wellbore operating system
US20050189119A1 (en) * 2004-02-27 2005-09-01 Ashmin Lc Inflatable sealing assembly and method for sealing off an inside of a flow carrier
EP1627986A1 (fr) * 2004-08-19 2006-02-22 Sunstone Corporation Obturateur anti-éruption rotatif

Cited By (36)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US9157285B2 (en) 2006-11-07 2015-10-13 Halliburton Energy Services, Inc. Offshore drilling method
US8887814B2 (en) 2006-11-07 2014-11-18 Halliburton Energy Services, Inc. Offshore universal riser system
US9127511B2 (en) 2006-11-07 2015-09-08 Halliburton Energy Services, Inc. Offshore universal riser system
US9376870B2 (en) 2006-11-07 2016-06-28 Halliburton Energy Services, Inc. Offshore universal riser system
US8033335B2 (en) 2006-11-07 2011-10-11 Halliburton Energy Services, Inc. Offshore universal riser system
US9127512B2 (en) 2006-11-07 2015-09-08 Halliburton Energy Services, Inc. Offshore drilling method
US8776894B2 (en) 2006-11-07 2014-07-15 Halliburton Energy Services, Inc. Offshore universal riser system
US9085940B2 (en) 2006-11-07 2015-07-21 Halliburton Energy Services, Inc. Offshore universal riser system
US9051790B2 (en) 2006-11-07 2015-06-09 Halliburton Energy Services, Inc. Offshore drilling method
US8881831B2 (en) 2006-11-07 2014-11-11 Halliburton Energy Services, Inc. Offshore universal riser system
US8281875B2 (en) 2008-12-19 2012-10-09 Halliburton Energy Services, Inc. Pressure and flow control in drilling operations
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
US8820405B2 (en) 2010-04-27 2014-09-02 Halliburton Energy Services, Inc. Segregating flowable materials in a well
US8261826B2 (en) 2010-04-27 2012-09-11 Halliburton Energy Services, Inc. Wellbore pressure control with segregated fluid columns
US8201628B2 (en) 2010-04-27 2012-06-19 Halliburton Energy Services, Inc. Wellbore pressure control with segregated fluid columns
US10145199B2 (en) 2010-11-20 2018-12-04 Halliburton Energy Services, Inc. Remote operation of a rotating control device bearing clamp and safety latch
US9163473B2 (en) 2010-11-20 2015-10-20 Halliburton Energy Services, Inc. Remote operation of a rotating control device bearing clamp and safety latch
US9957775B2 (en) 2011-03-01 2018-05-01 Conocophillips Company Well plug and abandonment choke insert
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
US9447647B2 (en) 2011-11-08 2016-09-20 Halliburton Energy Services, Inc. Preemptive setpoint pressure offset for flow diversion in drilling operations
US10233708B2 (en) 2012-04-10 2019-03-19 Halliburton Energy Services, Inc. Pressure and flow control in drilling operations
EP3047095A2 (fr) * 2013-09-20 2016-07-27 Weatherford Technology Holdings, LLC Utilisation d'un clapet d'isolement de fond de trou pour détecter une pression d'espace annulaire
US9650884B2 (en) 2013-09-20 2017-05-16 Weatherford Technology Holdings, Llc Use of downhole isolation valve to sense annulus pressure
AU2014321317B2 (en) * 2013-09-20 2017-06-15 Weatherford Technology Holdings, Llc Use of downhole isolation valve to sense annulus pressure
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