EP2904194B1 - Appareil et procédés à utiliser avec des fluides de forage - Google Patents

Appareil et procédés à utiliser avec des fluides de forage Download PDF

Info

Publication number
EP2904194B1
EP2904194B1 EP13748088.5A EP13748088A EP2904194B1 EP 2904194 B1 EP2904194 B1 EP 2904194B1 EP 13748088 A EP13748088 A EP 13748088A EP 2904194 B1 EP2904194 B1 EP 2904194B1
Authority
EP
European Patent Office
Prior art keywords
drilling fluid
conditioning device
tool
fluid
tubular string
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.)
Active
Application number
EP13748088.5A
Other languages
German (de)
English (en)
Other versions
EP2904194A2 (fr
Inventor
Andrew Philip Churchill
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.)
Churchill Drilling Tools Ltd
Original Assignee
Churchill Drilling Tools Ltd
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 Churchill Drilling Tools Ltd filed Critical Churchill Drilling Tools Ltd
Publication of EP2904194A2 publication Critical patent/EP2904194A2/fr
Application granted granted Critical
Publication of EP2904194B1 publication Critical patent/EP2904194B1/fr
Active legal-status Critical Current
Anticipated expiration legal-status Critical

Links

Images

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
    • E21B41/00—Equipment or details not covered by groups E21B15/00 - E21B40/00
    • E21B41/0078—Nozzles used in boreholes
    • 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
    • E21B21/002—Down-hole drilling fluid separation systems
    • 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
    • E21B21/06—Arrangements for treating drilling fluids outside the borehole
    • E21B21/062—Arrangements for treating drilling fluids outside the borehole by mixing components
    • 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

  • the invention relates to apparatus and associated methods for use with drilling fluid.
  • the invention relates to apparatus for conditioning of a drilling fluid for circulation downhole.
  • Certain embodiments relates to the apparatus and methods used when milling.
  • Drilling fluid In downhole operations, such as in the drilling of bores to access subsurface reservoirs (e.g. oil and gas reservoirs), drilling fluids are used to, among other things, remove drill cuttings and to cool drill bits.
  • Drilling fluid consists typically of a base liquid with various chemicals and powdered particles combined together in order to provide suitable properties to perform a particular downhole operation.
  • the base fluid is generally water or synthetic oil; and the powdered particles are usually clays (drilling fluid is often referred to as 'mud').
  • the various properties of the mud can be split into chemical and physical properties.
  • chemically the mud can be a particular acidity and salinity in order to minimize any chemical damage done by corroding metal parts down-hole or by dissolving/swelling various rock types through which the drilling is occurring.
  • the clays suspended in the mud are generally there to provide the useful physical properties for the mud, including density, viscosity and gel strength.
  • the density can provide a hydrostatic pressure overbalance on the fluid pressure in the rock, to prevent fluid flowing out of the surrounding formation and into the well (known as a kick, the precursor to a blow-out if left uncontrolled).
  • the viscosity can influence the ability of the mud to lift drilled cuttings out of a well, for example, as the mud flows back up an annulus between the drill pipe and the hole or the casing.
  • the gel strength influences the ability of the mud to 'set' when it is not flowing (drilling fluid is typically thixotropic), and can prevent the drilled cuttings from dropping back down the hole when the pumps are turned off (e.g. whilst making a connection or while tripping into or out of the well).
  • Drilling fluid normally operates hot because down hole temperatures are typically 120-140°C (248-284°F) but can get over 200°C (392°F). So the drilling fluid acts like a heat exchanger between the hot rock and the cold surface temperature.
  • Most mud is used for drilling, which tends to be a continuous operation with the mud circulating and in equilibrium, that is the mud properties are generally stable.
  • 'breaking circulation' to allow the gel's strength some time to reduce. After longer periods of mud stagnation (e.g.
  • Tight nozzles in the drill bit are used to jet the mud at the cutting face; this improves the rate of drilling penetration particularly in softer rocks. It is also known that that the nozzles assist in the shear thinning of the mud. However, this comes at a pressure/power/flow-rate cost to the mud pumps.
  • a rig will simply circulate mud through the string, doing nothing really productive until the mud is judged to be sufficiently conditioned.
  • Considerable rig time can be wasted 'circulating and conditioning' the mud; particularly in preparation for a milling operation, during which optimal drilling mud conditioning is critical for success.
  • a mill will be used in circumstances where is it necessary to cut the metal casing, for example to form a window in the casing, or when a section of casing simply needs to be ground away. This is often achieved by rotating a tungsten carbide cutter or bit/mill onto the casing to turn the casing into metal shavings/swarf, which then need to be flushed out of the hole by the mud.
  • Metal swarf is much denser than normal drilled rock, and has a tendency to clump, and thus the mud needs to be thicker and have a better gel strength to perform properly.
  • Starting milling before the mud is not sufficiently thinned and capable of being pumped at a rate sufficient to carry the the swarf out of the bore is likely to lead to blockage of the annulus with swarf, and the mill and the associated string becoming stuck in the bore, resulting in considerable damage to equipment and considerable and very expensive delay.
  • the combination of the viscous drilling fluid used in milling operations and the long circulation time may require the drilling fluid to be circulated for an extended period, for example 18 hours or more, before the fluid has been sufficiently conditioned and its viscosity reduced to permit the circulation rate to be increased to a rate sufficient for milling to commence.
  • the initial viscosity of the unconditioned drilling fluid places a high load on the fluid circulation apparatus, and it is not unknown for an operator to misjudge initial conditions and find that it simply is not possible to circulate the unconditioned fluid with the existing pumps and other equipment.
  • US4189243 (A ) describes a mud shearing device for placement in the mud flow line in a well drilling operation which includes a series of inner pressure chambers surrounded by concentric outer chambers with jet discharge ports connecting each inner chamber with a respective outer chamber and an inlet aperture connecting each succeeding inner chamber with a preceding outer chamber.
  • WO2011142894 (A1 ) describes a system for conditioning drilling fluid which includes a conditioning device having a first conduit configured to receive the drilling fluid, a flow restriction disposed adjacent the first conduit, the flow restriction comprising a fluid inlet and a fluid outlet, an impact plate disposed downstream of the flow restriction, a first chamber disposed between the flow restriction and the impact plate, and a second chamber disposed downstream of the impact plate, wherein the first chamber is fluidly connected to the second chamber.
  • a method for conditioning drilling fluid using a conditioning device includes pumping a drilling fluid through a flow restriction, accelerating the drilling fluid into a mixing chamber, subjecting the drilling fluid to elongational shearing, decelerating the drilling fluid against an impact plate, subjecting the drilling fluid to impact shearing, and emptying drilling fluid from the mixing chamber.
  • US3136583 describes a well drilling mud conditioning apparatus and method where clogging at the inlet end of the suction line is prevented by fragmenting congealed or coagulated masses in advance of the inlet to said line to produce small size particles which will not clog the inlet, and thereafter mixing said particles with water by means of suitable agitating blades within the suction line inlet so as to insure a drilling fluid or mud of substantially uniform consistency prior to its delivery to the usual mud pump.
  • WO0120121 (A1 ) describes a system which may include a separator at the sea floor adjacent the wellhead, which separates solids above a predetermined size from the wellstream.
  • the wellstream then enters one or more underwater pumps, which pump the wellstream to the surface.
  • a crusher as a separate unit, integrated in the separator or in the pump, receives the separated solids and reduces them to relatively small-sized particles.
  • the small particles are then pumped or moved to the surface by the pumps utilized for pumping the wellstream to the surface or by a separate underwater pump.
  • the separated solids are collected from the separator into a container, which container is then transported to the surface by a suitable method. Solids reaching the surface are removed to obtain filtered fluid, which after conditioning by conventional methods is pumped back into the wellbore as the drilling fluid.
  • a method for facilitating a downhole operation comprising:
  • a drilling fluid conditioning device comprising a tubular body configured for incorporation in a proximal portion of a tubular string extending to a distal downhole location, the body configured to induce shear thinning of fluid passing therethrough.
  • apparatus comprising:
  • drilling fluid conditioning device Rather than physically removing the drilling fluid conditioning device from the string it also possible to modify the device to, for example, remove a flow restriction from the device, or redirected fluid around or past the device.
  • the drilling fluid conditioning device may be configured to induce shear thinning of fluid passing therethrough, for example by accelerating the fluid.
  • shear thinning of fluid passing therethrough for example by accelerating the fluid.
  • the drilling fluid conditioning device may be incorporated in the circulation path for the drilling fluid only until the drilling fluid is judged to be suitably conditioned to permit a downhole operation to commence.
  • the downhole operation will be a cutting operation, such as drilling, reaming or milling.
  • a bypass tool may be incorporated in the tubular string, typically towards the distal end of the string, such that the drilling fluid may bypass the cutting tool during initial circulation. This may facilitate initiation of circulation of more viscous fluids, as the circulating fluid bypasses the nozzles in the cutting tool, and may facilitate higher circulation rates to accelerate the heating of the drilling fluid to a desired level.
  • the presence of an open bypass tool also allows the drilling fluid to be circulated without activating or actuating fluid-powered tools located below the bypass tool.
  • the presence of a bypass tool allows circulation of fluid at relatively high rates without activating a fluid pressure-actuated cutting tool with extendable cutting blades provided on the string below the bypass tool. This would allow the operator to rotate or reciprocate the string as the fluid is circulated, and further accelerate the conditioning of the fluid, safe in the knowledge that the cutters would not extend.
  • a drilling fluid apparatus and associated methods may be useful to reduce the time to condition mud sufficiently, prior to starting a milling operation.
  • the apparatus may be configured to condition a drilling fluid to be supplied to a downhole assembly.
  • the apparatus may comprise a conditioning device configured to thin the drilling fluid passing therethrough.
  • the apparatus may be configured to be positioned at a surface region of a wellbore.
  • the conditioning device may be configured to induce a shear flow in the fluid.
  • the conditioning device may be configured to induce a turbulent flow in the fluid.
  • the conditioning device may be configured to induce an eddy current flow in the fluid.
  • the conditioning device may be configured to stimulate, or generate, heating of the fluid.
  • the conditioning device may be configured to provide a friction in the fluid.
  • the conditioning device may be configured to provide an internal friction in the fluid.
  • the conditioning device may be configured to provide an increased internal friction in the fluid.
  • the conditioning device may be configured to provide an external friction with the fluid, such as a friction between the fluid and the apparatus, or between the fluid and a flowpath surface (e.g. a toolstring throughbore).
  • the conditioning device may be configured to provide an increased external friction with the fluid.
  • Conditioning may comprise modifying the drilling fluid.
  • Conditioning may comprise adapting the drilling fluid.
  • Conditioning may comprise altering a physical property of the drilling fluid.
  • Conditioning may comprise adjusting, or modifying, the viscosity of the drilling fluid.
  • Thinning may comprise reducing a viscosity of the fluid.
  • the conditioning device may comprise a flow restrictor.
  • the conditioning device may comprise a valve.
  • the conditioning device may comprise a nozzle.
  • the conditioning device may comprise a choke.
  • the conditioning device may comprise a throttle.
  • the conditioning device may comprise an inlet.
  • the conditioning device may comprise an outlet. The outlet may comprise a reduced cross-sectional area relative to the inlet.
  • the conditioning device may be variable.
  • the conditioning device may be adjustable.
  • the conditioning device may be removable.
  • the conditioning apparatus may be configured to permit selective positioning of the conditioning device.
  • the conditioning apparatus may be configured to permit removal and/or replacement of the conditioning device without retrieval of a toolstring.
  • the apparatus may be configured to provide downhole access, such as to a downhole tool, without requiring access through the conditioning device.
  • the conditioning device may be configured to induce a predetermined thinning of the fluid.
  • the conditioning device may be configured to induce a predetermined relative thinning of the fluid.
  • the conditioning device may be configured to induce a predetermined pressure differential in the fluid.
  • the conditioning device may be configured to provide a predetermined relative acceleration of the fluid.
  • the conditioning device may be configured to thin the fluid according to one or more characteristics of the fluid supplied to the conditioning device.
  • the characteristic may comprise a velocity.
  • the characteristic may comprise a temperature.
  • the characteristic may comprise a viscosity.
  • the conditioning device may be configured to condition a substantially cold drilling fluid.
  • the conditioning device may be configured to condition a substantially thick drilling fluid.
  • the conditioning device may be configured to receive the drilling fluid from a pump.
  • the drilling fluid may be supplied to the conditioning device from the pump.
  • the conditioning device may be configured to be located proximal to the pump.
  • the conditioning device may be configured to be located proximal to a BOP.
  • the conditioning device may be configured to be located proximal to a drill drive.
  • the conditioning device may be configured to be located proximal to the surface region.
  • the conditioning device may be configured to be located nearer to the surface region than to the downhole assembly.
  • the conditioning device may be configured to be located distal to the downhole assembly.
  • the apparatus may comprise a plurality of conditioning devices.
  • the plurality of conditioning devices may be arranged in parallel, and/or series (e.g. one after the other in the direction of flow).
  • the plurality of conditioning devices may be configured to provide a sequential thinning of the fluid.
  • the plurality of conditioning devices may be configured to provide a gradual thinning from an initial viscosity, uphole of a first device, to an exit viscosity downhole of a lowermost device.
  • the conditioning device may be configured to be located downhole of a drill drive.
  • the conditioning device may be configured to be located downhole of a surface drive, such as a rotary table or a topdrive.
  • the conditioning device may be configured to be located uphole of a drill drive.
  • the conditioning device may be configured to be located upstream of a drill drive.
  • the conditioning device may be configured to be located between a drill drive and the pump.
  • the conditioning device may be configured to be located between a surface drill drive, such as a rotary table or a topdrive, and the pump.
  • the conditioning device may be configured to be located uphole of a toolstring.
  • the conditioning device may form part of a toolstring (e.g. integrally formed).
  • the apparatus may be configured to attach to a toolstring.
  • the apparatus may be configured to be inline with a toolstring throughbore when in use.
  • the apparatus may be configured to supply a conditioned fluid to a throughbore.
  • the apparatus may be configured to supply the conditioned fluid to a throughbore directly from a conditioning device outlet.
  • the apparatus may be configured to provide a substantially uninterrupted flow of fluid from the conditioning device outlet.
  • the apparatus may comprise a tubular.
  • the conditioning device may be configured to be located at an upper portion of a toolstring; such as a drillstring or a milling string.
  • the conditioning device may be configured to be located at an uppermost portion of a toolstring; such as in a tubular coupled to a surface drive.
  • the apparatus may be configured to condition a drilling fluid for a milling operation.
  • the apparatus may be configured to condition a drilling fluid for a drilling operation.
  • the drilling fluid may comprise a milling fluid.
  • the drilling fluid may comprise a mud.
  • the apparatus may be configured for use with a milling tool.
  • the apparatus may be configured for use with a bypass tool.
  • the apparatus may comprise a milling tool.
  • the apparatus may comprise a bypass tool.
  • the apparatus may be configured for use with a reaming tool.
  • a method of conditioning a drilling fluid to be supplied to a downhole assembly According to an aspect of the invention there is provided a method of conditioning a drilling fluid to be supplied to a downhole assembly.
  • the method may comprise positioning a drilling fluid apparatus comprising a conditioning device at a surface region of a wellbore.
  • the method may comprise passing a drilling fluid through the conditioning device.
  • the method may comprise thinning the drilling fluid that passes through the conditioning device.
  • the method may comprise pumping the drilling fluid from a fluid source, such as a mud tank, to the conditioning device.
  • a fluid source such as a mud tank
  • the method may comprise passing the thinned fluid downhole through a drillstring to the downhole assembly.
  • the method may comprise passing the fluid through the conditioning device remotely from the downhole assembly.
  • the method may comprise passing the fluid through a substantial portion of the drillstring subsequent to passing through the conditioning device.
  • a conditioning device configured to thin a drilling fluid passing therethrough, and may comprising:
  • the outlet may provide a relative flow constriction, compared to the inlet portion.
  • the conditioning device may comprise an exit portion downhole of the outlet portion.
  • the exit portion may be configured to provide a substantially unimpeded flow of fluid.
  • the exit portion may comprise a throughbore to a toolstring.
  • the exit portion may comprise a substantially full diameter toolstring throughbore.
  • a drilling fluid apparatus configured to condition a drilling fluid to be supplied to a downhole assembly; the apparatus comprising a conditioning device configured to thin the drilling fluid passing therethrough; and the apparatus configured to be positioned at a surface region of a wellbore.
  • a method of conditioning a drilling fluid to be supplied to a downhole assembly According to an aspect of the invention there is provided a method of conditioning a drilling fluid to be supplied to a downhole assembly.
  • the method may comprise:
  • the invention includes one or more corresponding aspects, embodiments or features in isolation or in various combinations whether or not specifically stated (including claimed) in that combination or in isolation.
  • features recited as optional with respect to the one aspect may be additionally applicable with respect to the other aspects without the need to explicitly and unnecessarily list those various combinations and permutations here (e.g. the conditioning device of one aspect may comprise features of any other aspect).
  • Figure 1 shows a schematic view of apparatus 10 in accordance with an exemplary embodiment.
  • the apparatus 10 is shown in use in preparation for a milling operation, and can be considered to be mounted to an upper portion 12 of a drill pipe string 14 at a proximal or surface region 16.
  • the surface region is a rig floor.
  • the drill pipe 14 extends into and through a bore 18, and may be, for example, 2,450 to 3,050 metres (8,000 to 10,000 feet) long.
  • the bore 18 is a cased hole, in which a metal bore-lining casing has been cemented in place.
  • the drill pipe 14 has a milling tool 20 mounted at its lower or distal end, and which milling tool 20 forms part of a bottom hole assembly (BHA).
  • BHA bottom hole assembly
  • the milling tool 20 has cutters 22 powered by a differential piston and including a pressure-differential creating nozzle to selectively extend the cutters 22 when milling is desired.
  • the drill pipe 14 is rotated by a top drive 24 positioned above the apparatus 10.
  • the drill pipe 14 transfers rotation from the top drive 24 to the milling tool 20.
  • Drilling fluid i.e mud
  • the mud is pumped through the apparatus 10, and through a conditioning device (as will be further described below), downhole through a central throughbore 28 of the drill pipe 14 to the milling tool 20.
  • the mud supplied to the apparatus 10 from the mud pumps is generally unconditioned when starting the pumps after an extended period of inactivity, or when initiating an operation using a fresh batch of drilling fluid, or when switching drilling fluids. Accordingly, the mud is initially relatively cold and thick. As the mud is pumped downhole, the apparatus 10 facilitates conditioning of the mud, as will be described in more detail with reference to Figures 2 and 3 .
  • the bore 18 is plugged with a cement plug 17.
  • FIG. 2 shows a cross-sectional view of a portion of the apparatus 10 of Figure 1 ; and Figure 3 shows a detail view of the cross-section of Figure 2 .
  • the apparatus 10 is configured to facilitate conditioning of a drilling fluid prior to actuation of the milling tool 20.
  • the apparatus 10 comprises a conditioning device 15 configured to thin the drilling fluid passing therethrough.
  • the apparatus 10 is configured to be temporarily positioned in the drill string at the surface region 16 of the wellbore 18, at a proximal portion of the drill pipe string 14.
  • the conditioning device 15 has a tubular body 40, which is a relatively short sub in the embodiment shown (facilitating manual handling), with a box (female) connection 42 at the top 44 and a pin (male) connection 46 at the bottom 48.
  • a throat 50 of the box connection has a short wider bore section 52 with a 30 degree taper at the end 54 to house and support a nozzle seat ring 56.
  • the nozzle seat ring 56 has circumferential seals 58 in grooves 60 on its outer diameter to seal on the shorter wide bore section 52.
  • the nozzle seat ring 56 has an internal bore 62 and a shoulder 64 to house and support a changeable nozzle 66.
  • the nozzle 66 has seals 68 and grooves 70 on its outside to effect a seal to the internal bore 62 of the nozzle seat ring 56.
  • the nozzle 66 is made of case hardened steel.
  • the case hardened steel helps to prevent abrasive damage of the high velocity mud.
  • the nozzle is made of tungsten carbide or a hard ceramic or a steel spray coated with tungsten carbide.
  • mud can be pumped from the top 44 towards the nozzle 66, forcing the mud to speed up significantly as it passes through the nozzle 66.
  • the mud flows out into a larger internal diameter 71 than the internal diameter of the nozzle 66, creating various eddy currents and swirls in its wake.
  • This acceleration and subsequent vigorously turbulent situation causes the shearing effect which quickly conditions the mud (e.g. thins the mud for use).
  • the apparatus 10 can improve, or speeds up, the time taken to shear/condition the mud. This is assisted by placing the apparatus 10/conditioning device 15 at the beginning of a mud circulating system, at or near the surface region 16, which also facilitates removal of the apparatus 10 from the string once the mud has been conditioned sufficiently to permit the downhole operation, in this example a milling operation, to commence.
  • conditioning of the drilling fluid is further facilitated by provision of a bypass tool 29 above the milling tool 20.
  • the bypass tool 29 is operable to open bypass ports 30 to allow the mud to exit the drill pipe 14, with minimal restriction, into an annulus 32 between the drill pipe 14 and the bore 18, without having to pass through the milling tool 22 and the associated nozzles.
  • bypass ports 30 are initially opened to facilitate circulation of the drilling mud while the mud remains in an initial more viscous condition. Opening of the ports 30 also prevents radial extension of the cutters 22 before the mud has been suitably conditioned, allowing rotation and reciprocation of the string 14 without the cutters 22 engaging the casing.
  • Mud passed through the bypass tool 19 travels uphole in the annulus 32 to surface, where the mud is returned to the mud pumps via a flow line 34 to be treated or filtered and recirculated downhole, passing through the mud conditioning apparatus 10.
  • the mud is subject to shear thinning on passing through the apparatus 10 and as the mud travels downhole, the mud temperature rises. As the mud returns uphole, the mud cools, but is generally still warmer on reaching the surface 16 than surface ambient temperature.
  • the apparatus 10 is removed from the string 14 and the bypass ports 30 are closed. Subsequent circulation of mud will actuate the milling tool 20 and extend the cutters 22.
  • the mud exits the drill pipe 14 through nozzles in the milling tool 20 to cool the cutters 22, assist removal of cuttings and swarf, and to transport the cuttings and swarf to the surface 16.
  • the passage of the fluid through the milling tool nozzles also causes shear thinning of the fluid, thus assisting in maintaining the viscosity of the drilling fluid at a desirable level.
  • the conditioning device 15 does not restrict access to down-hole tools such as the bypass tool 19 or the milling tool 20, for example for activation by balls or darts, because the string may be broken below the apparatus 10 in conventional manner and the darts can be dropped from below the conditioning device 15.
  • the apparatus 10 can be very quickly removed from the system. Consequently, the power usage and flow restriction associated with the apparatus 10 is eliminated.
  • the absence of flow restrictions above the milling tool 20 is particularly useful in subsequent cleaning operations; the valve 19 may have relatively large unrestricted ports 30 so that at the end of the milling phase the tool 19 can be re-opened and used to pump fluid at a maximum flow rate to clean out all the swarf from the hole as quickly and efficiently as possible.
  • the milling operation may comprise a plurality of milling phases interspersed by clean-out phases, when the bypass tool 19 is employed to clear the annulus of swarf and other debris.
  • the sub 40 has an NC50 connection, with a 17.8 cm (7 inch) OD and a 7.6 cm (3 inch) ID.
  • the nozzle 66 shown has a 2.54 cm (1 inch) ID/Choke.
  • the nozzle 66 shown has a ratio of 3:1 in diameter.
  • the cross-sectional area is 9:1 and the kinetic energy increase at the choke is 81:1.
  • a typical 10 pound per gallon mud (1.2sg) pumped at 500 gpm (1890LPM) would create a pressure drop of about 250 psi (1,724 kPa/17 bar). This is basically pure shearing energy.
  • the nozzle is configured for use with a mud pump rated to have about 27,579 kPa (4000psi) of usable pressure.
  • the apparatus 10 can reduce the time required to condition the mud sufficiently to allow milling to commence. For example, where an operation may otherwise require 18 hours circulation to condition the mud, the apparatus 10 may condition the mud sufficiently within 6 hours of circulation. Accordingly, the apparatus 10 can save considerable valuable rig time.
  • the nozzle seat ring 56 has a tapered inlet 57.
  • the nozzle 66 has a tapered inlet 67.
  • the nozzle inlet 67 converges to a minimum inner diameter (ID/choke) before the diameter of the throughbore 28 sharply increases at a nozzle outlet 69.
  • the nozzle 66 is removable from the nozzle seat ring 56, through the box connection 42. Thus, if a different nozzle diameter is desired, the nozzle 66 can be removed and a different nozzle with a similar OD and different ID can be inserted into the nozzle seat ring 56. Likewise, if the nozzle 66 is damaged or needs replaced, a new nozzle can easily be inserted.
  • FIG. 4 shows a schematic view of an apparatus 110 in accordance with a second embodiment of the invention.
  • the apparatus 110 shown is generally similar to that shown in Figure 1 ; and as such like features share like reference numerals, incremented by 100.
  • the apparatus 110 comprises a conditioning device 115 with a tubular body 140 and a nozzle 166.
  • the tubular body 140 is a sub comprising two additional nozzles 194, 196 in series with the first nozzle 166. Accordingly, the mud is sequentially sheared and thinned as it passes through the succession of nozzles 166, 194, 196. Because the conditioning device 115 is at/near surface 116, it can be quickly and easily installed or removed as required.
  • any of the aforementioned apparatus may have other functions in addition to the mentioned functions, and that these functions may be performed by the same apparatus.
  • the apparatus may comprise a plurality of subs, each sub with a nozzle.
  • the subs may be connected together, or may have spacer subs located therebetween.
  • a nozzle with a 1.9 cm (0.75") choke ID and a similar drill pipe ID would create a pressure drop of around 797psi (54 bar) with a typical 10 pound per gallon mud (1.2sg) pumped at 500 gpm (1890LPM).
  • a typical 10 pound per gallon mud (1.2sg) pumped at 500 gpm (1890LPM) would create a pressure drop in a nozzle with an ID of 2.24 cm (0.88 inches) of around 430psi (29.3 bar) .
  • the nozzle/s could be installed within the circulating system of the rigs pipe-work; or as a bolt-on piece of kit to it as an addition to or a replacement for having the conditioning apparatus at the very top of the drill string near the drill floor.

Landscapes

  • Engineering & Computer Science (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Mechanical Engineering (AREA)
  • Earth Drilling (AREA)

Claims (17)

  1. Procédé destiné à faciliter une opération de forage, le procédé comprenant :
    le placement d'un dispositif de conditionnement de fluide de forage (15) dans une partie proximale d'une colonne tubulaire (14) afin de permettre le montage d'au moins un outil (20) sur une partie de forage distale de la colonne tubulaire (14) ;
    la circulation d'un fluide de forage le long d'un trajet d'écoulement de circulation de fluide comprenant le dispositif de conditionnement de fluide de forage (15) et la colonne tubulaire (14), afin de conditionner le fluide de forage ;
    la reconfiguration du trajet d'écoulement de circulation de fluide afin de contourner au moins une partie du dispositif de conditionnement de fluide de forage (15) ; et
    la circulation du fluide de forage conditionné dans la colonne tubulaire (14) et le au moins un outil (20).
  2. Procédé selon la revendication 1, comprenant la reconfiguration du trajet d'écoulement de circulation de fluide en retirant le dispositif de conditionnement de fluide de forage (15) de la colonne tubulaire (14).
  3. Procédé selon l'une quelconque des revendications précédentes, comprenant au moins l'un de ce qui suit :
    la reconfiguration du trajet d'écoulement de circulation de fluide en orientant le fluide de forage le long d'un trajet d'écoulement parallèle au dispositif de conditionnement de fluide de forage (15) ;
    la reconfiguration du trajet d'écoulement de circulation de fluide en reconfigurant le dispositif de conditionnement de fluide de forage (15).
  4. Procédé selon l'une quelconque des revendications précédentes, dans lequel le au moins un outil (20) comprend au moins l'un de ce qui suit :
    un outil de découpe ;
    une mèche de forage ;
    un aléseur ;
    une fraise, en option,
    dans lequel le au moins un outil (20) est au moins partiellement actionné par la pression de fluide.
  5. Procédé selon l'une quelconque des revendications précédentes, comprenant au moins l'un de ce qui suit :
    la circulation d'un fluide conditionné dans le au moins un outil (20) et l'actionnement de l'outil (20) ;
    la circulation d'un fluide conditionné par le biais de buses dans le au moins un outil (20).
  6. Procédé selon l'une quelconque des revendications précédentes, dans lequel le dispositif de conditionnement de fluide de forage (15), au moins :
    induit un cisaillement du fluide qui passe à l'intérieur ;
    accélère le fluide qui passe à l'intérieur ;
    réduit la viscosité du fluide qui passe à l'intérieur ;
    est retiré de la colonne tubulaire (14) lorsque le fluide de forage est conditionné à un degré suffisant pour permettre le fonctionnement du au moins un outil (20).
  7. Procédé selon l'une quelconque des revendications précédentes, comprenant au moins l'un de ce qui suit :
    le fait de prévoir une pluralité de dispositifs de conditionnement de fluide de forage (15) dans la colonne tubulaire (14) ;
    le fait de prévoir un outil de dérivation (29) dans la colonne tubulaire (14) au-dessus du au moins un outil (20) ;
    la circulation du fluide de forage le long d'un trajet d'écoulement de circulation de fluide comprenant le dispositif de conditionnement de fluide de forage (15), la colonne tubulaire (14), et un outil de dérivation ouvert (29), afin de conditionner le fluide de forage ;
    la circulation du fluide de forage dans la colonne tubulaire (14) et dans un outil de dérivation ouvert (29) tout en faisant tourner la colonne (14) ; la circulation du fluide de forage dans la colonne tubulaire (14) et un outil de dérivation ouvert (29) afin de nettoyer le puits ;
    la fermeture d'un outil de dérivation (29) situé dans la colonne tubulaire (14) au-dessus du au moins un outil (20), puis l'actionnement du au moins un outil (20) ;
    le placement du dispositif de conditionnement de fluide de forage (15) dans une partie de surface de la colonne tubulaire (14).
  8. Procédé selon l'une quelconque des revendications précédentes, dans lequel le dispositif de conditionnement de fluide de forage (15) comprend au moins l'un de ce qui suit :
    un limiteur de débit ;
    une buse (66).
  9. Procédé selon l'une quelconque des revendications précédentes, comprenant au moins l'un de ce qui suit :
    le placement du dispositif de conditionnement de fluide de forage (15) sous un entraînement supérieur (24) ;
    le placement du dispositif de conditionnement de fluide de forage (15) au-dessus d'une table rotative.
  10. Dispositif de conditionnement de fluide de forage (15) comprenant un corps tubulaire (40) configuré pour être intégré dans une partie proximale d'une colonne tubulaire (14) s'étendant jusqu'à un emplacement de forage distal, le corps (40) étant configuré pour induire un cisaillement du fluide qui passe à l'intérieur.
  11. Procédé selon la revendication 10, dans lequel le dispositif de conditionnement de fluide de forage (15) est configuré pour au moins l'un de ce qui suit :
    induire un cisaillement du fluide qui passe à l'intérieur ;
    accélérer le fluide qui passe à l'intérieur ;
    réduire la viscosité du fluide qui passe à l'intérieur ; et, en option dans lequel le corps tubulaire (40) comprend des raccords d'extrémité filetés.
  12. Procédé selon l'une quelconque des revendications 10 ou 11, dans lequel le dispositif de conditionnement de fluide de forage (15) comprend au moins l'un de ce qui suit :
    un limiteur de débit ;
    une buse (66), et, en option
    dans lequel le dispositif de conditionnement de fluide de forage (15) est configuré pour au moins l'un de ce qui suit :
    le placement dans une colonne tubulaire (14) sous un entraînement supérieur (24) ;
    le placement dans une colonne tubulaire (14) au-dessus d'une table rotative.
  13. Appareil comprenant :
    une colonne tubulaire (14) permettant le montage d'au moins un outil (20) sur une extrémité distale de la colonne (14) ; et
    un dispositif de conditionnement de fluide de forage (15) intégré à la colonne tubulaire (14) au niveau d'une partie proximale de la colonne (14),
    dans lequel le dispositif de conditionnement de fluide de forage (15) est configuré pour pouvoir être retiré de la colonne tubulaire (14) avant le fonctionnement du au moins un outil (20).
  14. Appareil selon la revendication 13, dans lequel le au moins un outil (20) comprend au moins l'un de ce qui suit :
    un outil de découpe ;
    une mèche de forage ;
    un aléseur ;
    une fraise, et, en option
    dans lequel le au moins un outil (20) est actionné par la pression de fluide, en option
    dans lequel le au moins un outil (20) possède des buses d'éjection.
  15. Appareil selon l'une quelconque des revendications 13 ou 14, dans lequel le dispositif de conditionnement de fluide de forage (15) est configuré pour au moins l'un de ce qui suit :
    pour induire un cisaillement du fluide qui passe à l'intérieur ;
    pour accélérer le fluide qui passe à l'intérieur ;
    pour réduire la viscosité du fluide qui passe à l'intérieur.
  16. Appareil selon l'une quelconque des revendications 13 à 15, comprenant au moins l'un de ce qui suit :
    une pluralité de dispositifs de conditionnement de fluide de forage (15) ;
    un outil de dérivation (29) dans la colonne tubulaire (14) au-dessus du au moins un outil (20) ; en option
    dans lequel le dispositif de conditionnement de fluide de forage (15) comprend au moins l'un de ce qui suit :
    un limiteur de débit ;
    une buse (66).
  17. Appareil selon l'une quelconque des revendications 13 à 16, dans lequel le dispositif de conditionnement de fluide de forage (15) est situé dans une partie de surface de la colonne tubulaire (14), en option
    dans lequel le dispositif de conditionnement de fluide de forage (15) est situé dans la colonne tubulaire (14) sous un entraînement supérieur (24), en option
    dans lequel le dispositif de conditionnement de fluide de forage (15) est situé dans une colonne tubulaire (15) au-dessus d'une table rotative.
EP13748088.5A 2012-08-13 2013-08-02 Appareil et procédés à utiliser avec des fluides de forage Active EP2904194B1 (fr)

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
GBGB1214444.0A GB201214444D0 (en) 2012-08-13 2012-08-13 Apparatus and methods for use with drilling fluids
PCT/GB2013/052072 WO2014027178A2 (fr) 2012-08-13 2013-08-02 Appareil et procédés à utiliser avec des fluides de forage

Publications (2)

Publication Number Publication Date
EP2904194A2 EP2904194A2 (fr) 2015-08-12
EP2904194B1 true EP2904194B1 (fr) 2018-04-25

Family

ID=46981465

Family Applications (1)

Application Number Title Priority Date Filing Date
EP13748088.5A Active EP2904194B1 (fr) 2012-08-13 2013-08-02 Appareil et procédés à utiliser avec des fluides de forage

Country Status (5)

Country Link
US (1) US20150204150A1 (fr)
EP (1) EP2904194B1 (fr)
CA (1) CA2880883A1 (fr)
GB (1) GB201214444D0 (fr)
WO (1) WO2014027178A2 (fr)

Families Citing this family (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US10408026B2 (en) * 2013-08-23 2019-09-10 Chevron U.S.A. Inc. System, apparatus, and method for well deliquification
US10151164B2 (en) 2014-03-31 2018-12-11 Schlumberger Technology Corporation Single-trip casing cutting and bridge plug setting
CN112360370B (zh) * 2020-10-20 2021-12-07 中国石油大学(北京) 旋转除垢解堵装置

Family Cites Families (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US3136583A (en) * 1960-08-05 1964-06-09 Bass Brothers Entpr Inc Mud cutter
US3867714A (en) * 1973-04-16 1975-02-18 Mobil Oil Corp Torque assist for logging-while-drilling tool
US4189243A (en) * 1978-01-25 1980-02-19 Black Wesley F In-line mud shearing apparatus
US6527054B1 (en) * 1999-09-14 2003-03-04 Deep Vision Llc Apparatus and method for the disposition of drilling solids during drilling of subsea oilfield wellbores
BR112012024871A2 (pt) * 2010-03-29 2016-06-14 Mi Llc bocal de cisalhamento de alta pressão para condicionamento em linha de lama de perfuração

Non-Patent Citations (1)

* Cited by examiner, † Cited by third party
Title
None *

Also Published As

Publication number Publication date
EP2904194A2 (fr) 2015-08-12
WO2014027178A2 (fr) 2014-02-20
US20150204150A1 (en) 2015-07-23
CA2880883A1 (fr) 2014-02-20
WO2014027178A3 (fr) 2014-11-13
GB201214444D0 (en) 2012-09-26

Similar Documents

Publication Publication Date Title
US20190106957A1 (en) Single-trip casing cutting and bridge plug setting
EP2428640B1 (fr) Système et procédé de commande de vitesses et pressions de circulation de slurry subterranéenne
CA2334741C (fr) Sabot de cuvelage pour forage
US10480290B2 (en) Controller for downhole tool
CN106460491B (zh) 形成多分支井的方法
MX2012008430A (es) Herramienta para despejar obstrucciones en el orificio de pozo y metodo para utilizarla.
AU2005311157B2 (en) Diverter tool
US20220298889A1 (en) Wellbore milling and cleanout system and methods of use
EP2904194B1 (fr) Appareil et procédés à utiliser avec des fluides de forage
WO2016022633A1 (fr) Outils de fraisage avec un système d'attrition secondaire
WO2021040532A1 (fr) Outil de coupe de tubage et procédé pour faire fonctionner l'outil de coupe de tubage - manchon de piston actionné par pression actionnant une soupape à bille
WO2021040531A1 (fr) Outil de coupe de tubage et procédé de fonctionnement de coupe de tubage
US11933174B2 (en) Modified whipstock design integrating cleanout and setting mechanisms
AU2011203566B2 (en) Systems and methods for using a passageway through a subterranean strata
EP3140495B1 (fr) Système et procédé de forage tubant
CA2752322A1 (fr) Systemes et procedes permettant d'utiliser un passage a travers une strate souterraine
OA18358A (en) Multi fluid drilling system

Legal Events

Date Code Title Description
PUAI Public reference made under article 153(3) epc to a published international application that has entered the european phase

Free format text: ORIGINAL CODE: 0009012

17P Request for examination filed

Effective date: 20150309

AK Designated contracting states

Kind code of ref document: A2

Designated state(s): AL AT BE BG CH CY CZ DE DK EE ES FI FR GB GR HR HU IE IS IT LI LT LU LV MC MK MT NL NO PL PT RO RS SE SI SK SM TR

AX Request for extension of the european patent

Extension state: BA ME

DAX Request for extension of the european patent (deleted)
GRAP Despatch of communication of intention to grant a patent

Free format text: ORIGINAL CODE: EPIDOSNIGR1

STAA Information on the status of an ep patent application or granted ep patent

Free format text: STATUS: GRANT OF PATENT IS INTENDED

INTG Intention to grant announced

Effective date: 20171006

GRAS Grant fee paid

Free format text: ORIGINAL CODE: EPIDOSNIGR3

GRAJ Information related to disapproval of communication of intention to grant by the applicant or resumption of examination proceedings by the epo deleted

Free format text: ORIGINAL CODE: EPIDOSDIGR1

GRAL Information related to payment of fee for publishing/printing deleted

Free format text: ORIGINAL CODE: EPIDOSDIGR3

STAA Information on the status of an ep patent application or granted ep patent

Free format text: STATUS: REQUEST FOR EXAMINATION WAS MADE

GRAA (expected) grant

Free format text: ORIGINAL CODE: 0009210

GRAR Information related to intention to grant a patent recorded

Free format text: ORIGINAL CODE: EPIDOSNIGR71

STAA Information on the status of an ep patent application or granted ep patent

Free format text: STATUS: THE PATENT HAS BEEN GRANTED

INTC Intention to grant announced (deleted)
AK Designated contracting states

Kind code of ref document: B1

Designated state(s): AL AT BE BG CH CY CZ DE DK EE ES FI FR GB GR HR HU IE IS IT LI LT LU LV MC MK MT NL NO PL PT RO RS SE SI SK SM TR

INTG Intention to grant announced

Effective date: 20180316

REG Reference to a national code

Ref country code: GB

Ref legal event code: FG4D

REG Reference to a national code

Ref country code: CH

Ref legal event code: EP

REG Reference to a national code

Ref country code: AT

Ref legal event code: REF

Ref document number: 993129

Country of ref document: AT

Kind code of ref document: T

Effective date: 20180515

REG Reference to a national code

Ref country code: IE

Ref legal event code: FG4D

REG Reference to a national code

Ref country code: DE

Ref legal event code: R096

Ref document number: 602013036495

Country of ref document: DE

REG Reference to a national code

Ref country code: NL

Ref legal event code: MP

Effective date: 20180425

REG Reference to a national code

Ref country code: LT

Ref legal event code: MG4D

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: NL

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180425

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: NO

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180725

Ref country code: LT

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180425

Ref country code: FI

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180425

Ref country code: SE

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180425

Ref country code: PL

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180425

Ref country code: ES

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180425

Ref country code: BG

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180725

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: RS

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180425

Ref country code: HR

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180425

Ref country code: LV

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180425

Ref country code: GR

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180726

REG Reference to a national code

Ref country code: AT

Ref legal event code: MK05

Ref document number: 993129

Country of ref document: AT

Kind code of ref document: T

Effective date: 20180425

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: PT

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180827

REG Reference to a national code

Ref country code: DE

Ref legal event code: R097

Ref document number: 602013036495

Country of ref document: DE

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: DK

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180425

Ref country code: AT

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180425

Ref country code: EE

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180425

Ref country code: CZ

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180425

Ref country code: RO

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180425

Ref country code: SK

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180425

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: IT

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180425

Ref country code: SM

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180425

PLBE No opposition filed within time limit

Free format text: ORIGINAL CODE: 0009261

REG Reference to a national code

Ref country code: DE

Ref legal event code: R119

Ref document number: 602013036495

Country of ref document: DE

STAA Information on the status of an ep patent application or granted ep patent

Free format text: STATUS: NO OPPOSITION FILED WITHIN TIME LIMIT

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: MC

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180425

REG Reference to a national code

Ref country code: CH

Ref legal event code: PL

26N No opposition filed

Effective date: 20190128

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: LU

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20180802

Ref country code: LI

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20180831

Ref country code: CH

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20180831

REG Reference to a national code

Ref country code: BE

Ref legal event code: MM

Effective date: 20180831

REG Reference to a national code

Ref country code: IE

Ref legal event code: MM4A

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: SI

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180425

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: DE

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20190301

Ref country code: IE

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20180802

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: BE

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20180831

Ref country code: FR

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20180831

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: AL

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180425

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: MT

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20180802

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: TR

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180425

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: CY

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180425

Ref country code: MK

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20180425

Ref country code: HU

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT; INVALID AB INITIO

Effective date: 20130802

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: IS

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20180825

REG Reference to a national code

Ref country code: GB

Ref legal event code: 732E

Free format text: REGISTERED BETWEEN 20230720 AND 20230726

PGFP Annual fee paid to national office [announced via postgrant information from national office to epo]

Ref country code: GB

Payment date: 20230822

Year of fee payment: 11