WO2014006149A2 - Appareil d'étanchéité annulaire dynamique - Google Patents

Appareil d'étanchéité annulaire dynamique Download PDF

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Publication number
WO2014006149A2
WO2014006149A2 PCT/EP2013/064172 EP2013064172W WO2014006149A2 WO 2014006149 A2 WO2014006149 A2 WO 2014006149A2 EP 2013064172 W EP2013064172 W EP 2013064172W WO 2014006149 A2 WO2014006149 A2 WO 2014006149A2
Authority
WO
WIPO (PCT)
Prior art keywords
sleeve
sealing
sealing apparatus
segments
inner tubular
Prior art date
Application number
PCT/EP2013/064172
Other languages
English (en)
Other versions
WO2014006149A3 (fr
WO2014006149A9 (fr
Inventor
Nils Lennart Rolland
Steinar Wasa Tverlid
Original Assignee
Statoil Petroleum As
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
Priority claimed from GB1212091.1A external-priority patent/GB2503741B/en
Priority claimed from GB1214898.7A external-priority patent/GB2505198B/en
Application filed by Statoil Petroleum As filed Critical Statoil Petroleum As
Publication of WO2014006149A2 publication Critical patent/WO2014006149A2/fr
Publication of WO2014006149A9 publication Critical patent/WO2014006149A9/fr
Publication of WO2014006149A3 publication Critical patent/WO2014006149A3/fr

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Classifications

    • EFIXED CONSTRUCTIONS
    • E21EARTH OR ROCK DRILLING; MINING
    • E21BEARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00Sealing or packing boreholes or wells
    • E21B33/02Surface sealing or packing
    • E21B33/08Wipers; Oil savers
    • E21B33/085Rotatable packing means, e.g. rotating blow-out preventers

Definitions

  • This invention relates to a dynamic annular sealing apparatus. Particularly, but not exclusively, the invention relates to a dynamic annular sealing apparatus for use in deepwater riserless drilling for the extraction of oil and gas. Aspects of the invention can be considered to provide a dynamic annular sealing apparatus for sealing an annular space between concentrically arranged tubulars.
  • Drilling without a riser can also improve the pressure conditions in a well by reducing the pressure difference at the well head (usually referred to as the riser margin), making riser disconnection less risky.
  • One of the challenges in achieving riserless drilling is to provide an effective annular seal on the drill string, including the bottom hole assembly with varying outer diameters, while also separating drilling fluid from the sea and surrounding environment.
  • a secondary challenge is to develop a seal that can be used in Managed Pressure Drilling (MPD) systems, where the aim is to better control the annular pressure profile throughout the wellbore, so as to allow MPD to be employed by floating drilling vessels.
  • MPD Managed Pressure Drilling
  • US7,926,593 B1 is directed towards a method for converting a drilling rig between conventional hydrostatic pressure drilling and managed pressure drilling or underbalanced drilling using a docking station housing, and, along with the prior art referred to therein, describes further background to the present invention. It is an aim of the present invention to provide a dynamic annular seal which addresses at least some of the afore-mentioned problems. Summary of the Invention
  • a dynamic annular sealing apparatus comprising: a resilient sleeve deformable between a closed sealing configuration and an open non-sealing configuration; and a pump controllable to effect such deformation by alteration of pressure exerted on the sleeve.
  • embodiments of the present invention provide a dynamic annular sealing apparatus (i.e. RCD) which is controllably deformable from a narrow sleeve capable of sealing against an inner tubular to a wide sleeve allowing free-running of tubulars there-within.
  • RCD dynamic annular sealing apparatus
  • a particular advantage over known technology is that embodiments of the invention can be configured to allow full, unencumbered, access to a borehole with the seal still in place (i.e. by deforming the sleeve so as to provide an opening equivalent to the full borehole inner diameter).
  • the sealing apparatus may be suited for use in a borehole or drilling riser application, and may be particularly suited to deep water subsea applications. More specifically, the apparatus may be employed in a so-called blow-out preventer (BOP) commonly mounted adjacent the seabed at the top of a wellbore.
  • BOP blow-out preventer
  • the apparatus may be configured to maintain a desired annular pressure in the wellbore (below) and/or to prevent seawater or base fluid in a riser (above) from mixing with drilling fluid below.
  • the apparatus may seal against pressure both downstream and upstream.
  • the apparatus can be used to maintain a desired pressure in the wellbore which is either higher or lower than ambient pressure. This allows drilling through tight pressure margins using either managed pressure drilling or underbalanced drilling.
  • embodiments of the present invention can seal against several different diameters of inner tubulars (e.g. drillpipes and tooling) without requiring the sealing element to be changed.
  • inner tubulars e.g. drillpipes and tooling
  • conventional subsea seals need to be retrieved and replaced multiple times during a drilling operation since they are not adjustable in the same manner as the present sealing apparatus.
  • the sleeve may be biased towards the closed sealing configuration. Accordingly, with no pressure differential applied to the sleeve, the sleeve may adopt the closed sealing configuration, which will conveniently be such that it will form a sealing contact with a desired minimum diameter inner tubular.
  • the sleeve may be constituted by a waisted annular band (hyperboloid) having a smaller inner diameter at its centre and a larger inner diameter at each end.
  • the sleeve may be formed of polymeric material, more particularly elastomeric material and, in some embodiments may be formed of rubber.
  • the sleeve may contain material to mitigate wear.
  • the material may be embedded in the sleeve.
  • the material may comprise fine grade hard or plastic material, for example, silicate, ceramic or diamond pieces.
  • the pump may be arranged to provide suction (i.e. below ambient pressure) to deform the sleeve into the open non-sealing configuration.
  • the pump may further be arranged to provide increased pressure (i.e. above ambient pressure) to increase the sealing force of the sleeve in the closed configuration.
  • the pump may be controlled to adjust the physical force applied by the sleeve to an inner tubular and, in doing so, the sleeve may remain in sealing contact with the inner tubular even when the diameter of the inner tubular changes, for example, when tools are provided along the length of a drill string.
  • the sleeve may be provided within a cylindrical housing having inwardly directed top and bottom flanges, clamps, connectors or the like to contain the sleeve therein. Each end of the sleeve may be in sealing engagement with the housing so as to define a cavity between the outer longitudinal surface of the sleeve and the housing.
  • the pump may be connected to the cavity by a fluid conduit such that operation of the pump may increase or decrease the fluid pressure in the cavity and thereby deform the sleeve.
  • At least one end of the sleeve may be axially moveable within the housing to accommodate deformation of the sleeve.
  • the at least one end of the sleeve may be fixed (e.g. vulcanised) to a metal (e.g. steel) ring configured for axial movement within the housing.
  • the other end of the sleeve may also be fixed (e.g. vulcanised) to a metal (e.g. steel) ring.
  • the pump may be connected to a hydraulic reservoir via an inlet.
  • the hydraulic reservoir may be balanced to ambient pressure.
  • the pump power will be proportional to the pressure at the seabed, which will be significant in deep water drilling applications.
  • At least one pressure sensor may be provided.
  • the at least one pressure sensor may be in communication with a control system configured to regulate the pump to adjust the pressure in the cavity and thereby adjust the sealing force and/or degree of opening of the sleeve.
  • the at least one pressure sensor may be provided in the fluid conduit and/or borehole.
  • An accumulator may be provided to compensate for variations in the volume of the cavity due to deformation of the sleeve (e.g. such as would result from variations in the outer diameter of a drill string as it passes through the sleeve).
  • the accumulator may be connected to the fluid conduit.
  • a retainer pipe may be at least partially inserted into the sleeve so as to hold at least one end of the sleeve open.
  • the sealing apparatus may be configured for sealing an annular space between concentrically arranged tubulars.
  • a tubular net formed by a multiplicity of resiliency deformable segments interconnected by means of flexible joints may be at least partially embedded within the
  • Such embodiments of the invention provide a flexible annular sealing apparatus which is deformable from a narrow sleeve to a wide sleeve and which comprises a robust and reliable construction having improved wear and sealing lifespan and no rotating parts.
  • the construction of the apparatus also provides a degree of flexibility ensuring that varying diameters of tubulars (e.g. associated with different tooling) can be securely accommodated, even within a single seal.
  • the inwardly directed restoring or sealing force of the apparatus will also tend to increase such that the apparatus will be easy to use as it will be biased towards contracting around an inner tubular.
  • the sleeve will automatically contract around an inner tubular to seal there-against.
  • the sleeve will continue to provide good, possibly even improved, sealing characteristics in the case of an emergency well event such as a blowout which causes an increase in pressure surrounding the seal, resulting in an increased force being applied to the inner tubular.
  • the pump may be employed to enhance or counteract the inherent biasing force of the sleeve so as to more accurately control the sealing characteristics of the sleeve.
  • the apparatus may be employed in a number of different wellbore applications, for example, between a drill string and a riser (e.g. at the sea bed), as a blowout prevention (BOP) annular seal, as a seal in riserless drilling, and in Managed Pressure Drilling (MPD), Underbalanced Drilling or Dual Gradient Drilling systems.
  • BOP blowout prevention
  • MPD Managed Pressure Drilling
  • the apparatus may further be suitable for sealing an annular space between non-concentrically arranged tubulars.
  • the apparatus may be used as a single seal or employed to form a series of multiple seals, for example, to enable a lubricator function for a bottom hole assembly (BHA).
  • BHA bottom hole assembly
  • the seal may be configured as a loose mud scraper provided on a rig floor to scrape mud from an inner tubular.
  • the seal may be employed in well interventions such as snubbing operations or in any operation where a wireline, pipe or coiled tubing is required to be run through a stuffing box.
  • the flexible joints may be configured to allow the segments to fold over each other when the sleeve is in a collapsed configuration and to lever the segments apart when the sleeve is in an expanded configuration.
  • the segments may be interconnected by way of hinged joints having axes of rotation which are substantially radially aligned with respect to the sleeve.
  • Each segment of the net may be coupled at each of its ends to a set of neighbouring segments by a bolt having an axis aligned substantially radially with respect to the sleeve. Intermediate segments of the net may be coupled at each end to three neighbouring segments.
  • the net may comprise a series of flexible quadrilateral elements.
  • the segments may be of metal (e.g. steel).
  • Each segment may be substantially planar in its undeformed state, such that when the sleeve is expanded the segments are deformed, resulting in a radially inward force being exerted by the sleeve.
  • the segments may be formed of metal rope or the like.
  • the sealing apparatus may be configured for use with a rotating or non-rotating inner tubular such as a drill string.
  • radially inwardly facing surfaces of the segments may be exposed and may project from the sleeve so that, in use, these surfaces of the segments come into contact with an inner tubular, thereby reducing the friction between the apparatus and the inner tubular.
  • the surfaces may be provided with a relatively low friction coating to facilitate insertion and/or rotation of the inner tubular within the sleeve.
  • the coating may comprise a ceramic or polymer coating but is not limited thereto.
  • both friction and wear between the apparatus and the inner tubular can be controlled through selective use of a material having the desired friction/wear and sealing properties at the interface between the segments and the inner tubular.
  • the interface material need not be chosen for its elastic properties also, as is the case for traditional BOP annular seals, since in accordance with the present invention, the elastic properties are catered for by the provision of the deformable sleeve and flexible net.
  • the sleeve may be configured to have a large operating range, for example, by having an outer diameter which can flex from at least 6.625 inches (approximately 0.19m) to at least 18.75 inches (approximately 0.48m), thus making the sleeve suitable for use with drill pipes and slick drill collars.
  • a method of installing an apparatus for sealing an annular space between concentrically arranged tubulars comprising:
  • An expansion member may be employed to expand the sleeve for receipt of the retainer pipe.
  • the retainer pipe may be arranged to hold just one end of the sleeve open or may expand along the entire length of the sleeve. Once the inner tubular is inserted, the retainer pipe may be fully or partially withdrawn from within the sleeve.
  • the retainer pipe may be constituted by a full bore pipe section such that the sleeve is pre-tensioned and "parked” around the full bore pipe section and wherein the retainer pipe can be moved axially to expose the sleeve to an inner tubular (e.g. drill pipe), which the sleeve will automatically clamp onto due to the restoring forces in the net.
  • an inner tubular e.g. drill pipe
  • the full bore pipe section may be run back into the sleeve such that the sleeve will again be pre- tensioned and "parked” behind the full bore pipe, ready to be deployed around a subsequent inner tubular as and when required.
  • the full bore pipe which energises and offloads the sleeve by sliding up and down, may allow full access to the bore (the same as a BOP stack bore) when the sleeve is not required and is parked.
  • the apparatus is particularly suited to sealing an opening between a subsea riser and a tubular extending through the riser and out of an end of the riser.
  • This tubular may be a drill string.
  • a tubular retainer pipe can be inserted between the inner tubular and the sleeve in order to radially expand at least a portion of the sleeve and force its outer surface into sealing contact with the inner surface of the riser, whilst an unexpanded portion of the sleeve remains tightly sealed against the inner tubular.
  • the apparatus may also be used downhole to seal components other than a riser.
  • the apparatus may be installed down hole and configured to seal automatically if an external annular pressure reaches a pre-determined level (i.e. becomes too high) relative to an internal string pressure.
  • a pre-determined level i.e. becomes too high
  • the apparatus will also make it easier to work through the kick and regain integrity since one can operate though a bore of the sleeve like normal (as long as the retainer pipe or inner tubular is not pulled out).
  • the elastically deformable material may comprise rubber, more specifically although not limited to, vulcanised rubber.
  • Figure 1 shows a cross-sectional view of a dynamic annular sealing apparatus in accordance with a first embodiment of the present invention, in a closed configuration
  • Figure 2 shows a cross-sectional view of the dynamic annular sealing apparatus of Figure 1 , in an open configuration
  • Figure 3A shows a plan view of a portion of a tubular net in accordance with a second embodiment of the present invention, in both an expanded configuration and a contracted configuration;
  • Figure 3B shows a side perspective view illustrative of one segment of the tubular net illustrated in Figure 3A;
  • Figure 3C shows a side perspective view illustrative of two segments from the tubular net of Figure 3A, coupled together with a flexible joint;
  • Figure 4A illustrates a tubular net similar to that shown in Figure 3A, provided around an inner tubular
  • Figure 4B illustrates the forces causing elastic deformation of a segment of the net shown in Figure 4A, when it is wrapped around an inner tubular;
  • Figure 4C illustrates the deformed shape of segments of the net as a result of the forces illustrated in Figure 4B;
  • Figure 5 shows a deformed segment in the form it would adopt when in a net wrapped around an inner tubular as per Figure 4C;
  • Figure 6A shows a side perspective view of a segment of a tubular net in accordance with another embodiment of the invention, comprising a low friction coating on its underside;
  • Figure 6B shows a cross-sectional view taken along the dashed centre line shown in Figure 6A, when the segment is provided on an inner tubular;
  • Figure 7 illustrates the sealing capacity of a tubular net in accordance with an embodiment of the present invention
  • Figure 8A illustrates a top and side view of an unexpanded tubular net in accordance with an embodiment of the present invention
  • Figure 8B illustrates the tubular net of Figure 8A once incorporated into a sleeve of elastically deformable rubber to form a sealing apparatus in accordance with an embodiment of the invention
  • Figure 8C shows the sealing apparatus of Figure 8B provided within an outer tubular housing in, for example, a wellbore
  • Figure 8D shows a retainer pipe prior to insertion into the sealing apparatus of Figure 8C.
  • Figure 8E shows the top of the sealing apparatus being held in an expanded configuration to allow insertion of the retainer pipe into the apparatus
  • Figure 9A shows the sealing apparatus of Figures 8B to 8E in stand-by mode with the retainer pipe provided through the sealing apparatus such that the sealing apparatus is expanded energized (pressing strongly towards the retainer pipe ready to seal if the retainer pipe is removed) and primed for use;
  • Figure 9B shows the sealing apparatus of Figure 9A in use whereby the retainer pipe is withdrawn to allow the sealing apparatus to contract around a smaller inner tubular - the arrows also illustrate that if the apparatus is exposed to high external pressures, these pressures will contribute to a higher sealing force which is important for a good sealing;
  • Figure 10A shows a transverse cross-sectional view of the apparatus when contracted around an inner tubular
  • Figure 10B shows a side view of apparatus of Figure 10A
  • Figure 1 1 A shows the apparatus of Figure 10B adapted to seal around an inner tubular having a varying outer diameter
  • Figure 1 1 B shows the apparatus of Figure 1 1 A returning to seal the inner tubular as the varying outer diameter portion is extracted from the apparatus;
  • Figure 12 shows the apparatus of Figure 10B fitted with an emergency closure pipe from below.
  • FIG. 1 With reference to Figures 1 and 2, there is illustrated a dynamic annular sealing apparatus in accordance with a first embodiment of the present invention, in a closed and an open configuration, respectively.
  • the apparatus comprises a hydraulic pump 1 and an annular resiliency deformable sleeve seal 2.
  • the apparatus is shown in operation, with a drill string 3 extending through the opening (i.e. bore) of the seal 2.
  • Figure 1 shows the seal 2 in a neutral position (i.e. without any external pressure differential), which takes the shape of a hyperboloid.
  • the centre of the seal 2 is shown in a relaxed state which, in this case, is arranged such that the seal 2 is in sealing contact with a desired minimum diameter drill string 3.
  • the seal 2 may be arranged such that in its relaxed states its centre is disposed part-way between the drillstring 3 and a surrounding housing 5, or it may be close to or adjacent the drill string or even providing an inwards force against the drill string 3.
  • the housing 5 in which the seal 2 is provided is cylindrical and, in this case, is provided in an expanded head of a wellbore 6.
  • Each end 8 of the seal 2 is in sealing engagement with the housing 5 so as to define a cavity 7 between the outer longitudinal surface of the seal 2 and the housing 5.
  • the pump 1 is connected to the cavity 7 by a fluid conduit 4 such that operation of the pump 1 may increase or decrease the fluid pressure in the cavity 7 to thereby deform the seal 2.
  • the housing 5 comprises inwardly directed top and bottom flanges 9 to contain the seal 2 therein.
  • the lower end 8 of the seal 2 is axially moveable within the housing 5 to accommodate deformation of the seal 2 such as when it is retracted to the open configuration shown in Figure 2.
  • the seal 2 is formed from rubber and the lower end 8 is vulcanised to a steel ring 10 slidably mounted in the housing 5.
  • the seal 2 comprises embedded diamond pieces to mitigate material wear.
  • the pump 1 is connected to an ambient pressure hydraulic reservoir 1 1 via an inlet 12.
  • an accumulator 13 is connected to the fluid conduit 4 to compensate for variations in the volume of the cavity 7 due to deformation of the seal 2.
  • a first pressure sensor 14 is provided in the fluid conduit and a second pressure sensor 15 is provided in the wellbore 6, downstream of the seal 2. Both pressure sensors 14, 15 are configured to communicate their respective pressure readings to a control system 16 which is provided on a surface rig (not shown).
  • the control system 16 is configured to regulate the pump 1 to adjust the pressure in the cavity 7 and thereby adjust the sealing force and/or degree of opening of the sleeve, for example, to maintain sealing contact with the drillstring 3 even as tools 17 of different diameter are feed through the apparatus.
  • Further pressure sensors may also be also be incorporated, for example, to monitor the pressure upstream of the seal (e.g. in a riser).
  • the pressure exerted by the seal 2 on the drillstring 3 can be augmented by operating the pump 1 so as to provide above ambient pressure in the cavity 7.
  • the apparatus can be used to seal the annulus between the housing 5 and the drillstring 3 to thereby retain a desired pressure in the wellbore 6.
  • FIG. 3A there is illustrated a portion of a tubular net 1 10 in accordance with an embodiment of the present invention, in both an expanded configuration 1 12 and a contracted configuration 1 14.
  • the net 1 10 comprises a multiplicity of resiliency deformable steel segments 1 16 interconnected by means of flexible joints 1 18.
  • the net 1 10 will be partially embedded in a rubber sleeve to form a sealing apparatus in accordance with a second embodiment of the present invention.
  • Each segment 1 16 of the net 1 10 is coupled at each of its ends to a set of neighbouring segments 1 16 by a bolt 120. As shown in Figure 3A, intermediate segments 1 16 of the net 1 10 are coupled at each end to three neighbouring segments 1 16 so as to form a series of flexible quadrilateral elements 122.
  • each segment 1 16 is substantially planar in its undeformed state, with the plane of each segment 1 16 extending radially with respect to the tubular structure of the net 1 10.
  • a first end of the segment 1 16 is provided with a first coupling 124 and a second end of the segment 1 16 is provided with a second coupling 126.
  • the first and second couplings 124, 126 are configured to engage with one another so that, as shown in Figure 3C, the second coupling 126 of one segment 1 16 can engage with the first coupling 124 of another segment 1 16 and the bolt 120 can pass through the engaged first and second couplings 124, 126 to hingably connect the two segments 1 16 together.
  • the hinged joints 1 18 have an axis of rotation which is substantially radially aligned with respect to the tubular structure of the net 1 10.
  • FIG 4A illustrates a tubular net 1 10 similar to that shown in Figure 3A, provided around an inner tubular 130.
  • each of the segments 1 16 will be deformed so as to allow the net 1 10 to encircle the inner tubular 130. More specifically, as shown in Figure 4B for a specific segment 1 16A (which is curving downwardly from left to right in Figure 4A), each segment 1 16 will be subject to opposed twisting forces.
  • each segment 1 16 of the tubular net 1 10 will increase as the diameter of the net 1 10 is increased and this will set up a force that will try to collapse the net 1 10 and which, in turn, will serve to seal the net 1 10 against the inner tubular 130.
  • Figure 5 shows a single deformed segment 1 16 in the form it would adopt when part of the net 1 10 is wrapped around the inner (hollow) tubular 130.
  • the first and second couplings 124, 126 (through which the bolts 120 pass) each have an axis 136 which is perpendicular to the surface of the inner tubular 130. Consequently, the forces between each segment 1 16 will be evenly distributed and each segment 1 16 will adopt a shape having an underside 138 which follows the surface of the inner tubular 130 tangentially.
  • the length of each segment 1 16 (or each set of two adjacent stiff segments) will be restricted by the need for each segment 1 16 to deform sufficiently so that it follows and seals against the circumference of the inner tubular 130.
  • the underside 138 is provided with a low friction polymer coating 140 (or a coating of another material) that exhibits low friction and low wear characteristics on the inner tubular 130 (which may comprise steel), and which has the ability to seal one side of the segment 1 16 from the other - ⁇ .
  • a low friction polymer coating 140 or a coating of another material
  • the cross-sectional configuration of the polymer coatingl 40 shown in Figure 6B is for illustrative purposes only and other cross-sections may be employed to achieve the desired sealing effect.
  • Figure 7 illustrates the sealing capacity of the tubular net 1 10.
  • the sealing capacity of the net 1 10 is determined by the sum of the force provided by each circumferential band of segments 1 16 and the sealing capacity of each joint 1 18 is determined as twice the restoring force associated with a single segment 1 16.
  • the net 1 10 comprises six bands, each providing a pressure of 100 bar, the net 1 10 will have a total sealing capacity of 600 bar.
  • the restoring forces experienced by each segment 1 16 will increase as the diameter of the net 1 10 is increased and so the sealing capacity will also increase accordingly.
  • FIGs 8A through 8E illustrate the assembly and installation of an apparatus 150 according to an embodiment of the present invention.
  • a tubular net 1 10 as described above is first formed from a multiplicity of resiliency deformable segments 1 16 interconnected by means of flexible joints 1 18, as shown in Figure 8A.
  • the net 1 10 is then partially embedded within the inner surface of a sleeve 152 of elastically deformable vulcanised rubber, as shown in Figure 8B, to form the apparatus 150.
  • the apparatus 150 is then inserted (in a relaxed or collapsed state) into an outer tubular 160 which, in this case, is constituted by an expanded head of a wellbore as shown in Figure 8C.
  • the apparatus 150 may be expanded by an expansion member in the form of a funnel which can be pulled through the apparatus 150 allowing the retainer pipe 162 to follow the large end of the funnel such that the retainer pipe 162 is then partially inserted into the apparatus 150 so as to hold at least one end 164 of the apparatus 150 open for subsequent receipt of an inner tubular.
  • the end 164 of the apparatus 150 may then be fixedly secured to the outer tubular 160 for subsequent operation.
  • the retainer pipe 162 may be inserted into the apparatus 150 as a manufacturing step.
  • Figure 9A shows the apparatus 150 of Figures 8B to 8E in a stand-by mode with the retainer pipe 162 inserted along the entire length of the apparatus 150 such that the apparatus 150 is stretched and expanded against the inner surface of the outer tubular 160 and is thereby provided with potential energy ready for use.
  • the inner surface of the retainer pipe 162 will surround the inner, usable portion of the wellbore at full bore width.
  • Figure 9B shows the apparatus 150 in use whereby the retainer pipe 162 has been partially withdrawn to allow the apparatus 150 to contract around and seal against a smaller inner tubular 166 in the form of a drill string which is provided through the retainer pipe 162.
  • any increase in external pressure due to a wellbore issue will enhance the sealing capacity of the apparatus 150 such that it will more tightly seal against the inner tubular.
  • the upper end of the apparatus 150 is brought into sealing contact with the inner surface of the outer tubular 160 thereby preventing flow from passing around the apparatus 150 in a vertical direction.
  • the upper end of the apparatus 150 may be held or fixed in sealing contact with the outer tubular 160.
  • the sealing contact with the outer tubular 160 may be provided at the lower end of the apparatus 150, or part-way along its length. It will be understood that, as illustrated in Figure 9B, the apparatus 150 is primarily configured to seal against external pressure acting on the apparatus from below.
  • the apparatus 150 may be inverted such that the sealing contact with the outer tubular 160 is downstream of the high pressure area. Consequently, in order to seal against external pressure from both directions (above and below), two oppositely orientated sets of apparatus 150 may be provided with the sealing contact of each with the outer tubular 160 provided in the centre.
  • the two sets of apparatus described could also be integrated in a single apparatus configured for external sealing contact at its centre.
  • FIGs 10A and 10B when the apparatus 150 is contracted around the inner tubular 166, gaps 168 are provided between the outer surface of the inner tubular 166 and the rubber 152 due to the partially exposed ends of the segments 1 16, which are provided with the polymer coating 140.
  • there is low friction between the apparatus 150 and the inner tubular 166 making it much easier to manoeuvre and rotate the inner tubular 166 within the apparatus 150.
  • Figure 1 1 A shows the apparatus of Figure 10B adapted to seal around an inner tubular 170 having a varying outer diameter. More specifically, the retainer pipe 162 has been partially withdrawn to expose the apparatus 150 to the inner tubular 170 which comprises a radially expanded portion 172 part-way along its length. Notably, the apparatus 150 has adapted to expand around the portion 172 but is still contracted around the remaining narrow regions of the inner tubular 170 to completely seal against the inner tubular 170.
  • Figure 1 1 B shows the apparatus 150 returning to seal a narrow region of the inner tubular 170 as the expanded portion 172 is extracted from the apparatus 150.
  • the apparatus 150 can easily adapt to different outer diameters (such as may be encountered with wellbore tooling) while continuously and firmly tightening around the tool surface and returning to a desired outer diameter when required.
  • this process is reversible such that Figure 1 1 B can also be interpreted to show how the apparatus 150 would behave when the larger portion 172 of the drill pipe is on its way upwards expanding the lower end of the apparatus 150.
  • the apparatus 150 can be locked in place by providing an emergency closure pipe 180 forced around the apparatus 150 from below, as shown in Figure 12.
  • the emergency closure pipe 180 in this example is constituted by a hollow steel pipe having an inwardly tapering (i.e. funnelled) leading edge 182 which forces the apparatus 150 inwardly such that the apparatus 150 adopts an outer diameter which matches the inner diameter of the emergency closure pipe 180.
  • the net 1 10 can ensure no contact between the inner tubular 170 and the rubber 152 so that friction is low and, in certain embodiments, a metal-to- metal seal can be provided, in particular, where a metal funnel (e.g. constituted by the emergency closure pipe 180) is used to lock the seal.
  • a metal funnel e.g. constituted by the emergency closure pipe 180

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

Abstract

L'invention se rapporte à un appareil d'étanchéité annulaire dynamique comprenant un manchon élastique pouvant se déformer entre une configuration d'étanchéité fermée et une configuration de non-étanchéité ouverte, et une pompe pouvant être commandée pour effectuer une telle déformation par la modification de la pression exercée sur le manchon. L'appareil est particulièrement adapté pour être utilisé dans des applications de puis de forage.
PCT/EP2013/064172 2012-07-06 2013-07-04 Appareil d'étanchéité annulaire dynamique WO2014006149A2 (fr)

Applications Claiming Priority (4)

Application Number Priority Date Filing Date Title
GB1212091.1 2012-07-06
GB1212091.1A GB2503741B (en) 2012-07-06 2012-07-06 Dynamic annular sealing apparatus
GB1214898.7 2012-08-21
GB1214898.7A GB2505198B (en) 2012-08-21 2012-08-21 Apparatus for sealing an annular space between concentrically arranged tubulars

Publications (3)

Publication Number Publication Date
WO2014006149A2 true WO2014006149A2 (fr) 2014-01-09
WO2014006149A9 WO2014006149A9 (fr) 2014-03-06
WO2014006149A3 WO2014006149A3 (fr) 2014-11-20

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Cited By (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US9540898B2 (en) 2014-06-26 2017-01-10 Sunstone Technologies, Llc Annular drilling device
CN113236782B (zh) * 2021-04-29 2023-11-17 西安航天精密机电研究所 一种耐高压低摩擦的动密封结构
WO2024081547A1 (fr) * 2022-10-12 2024-04-18 Baker Hughes Oilfield Operations Llc Vanne, procédé et système

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EP1627986A1 (fr) * 2004-08-19 2006-02-22 Sunstone Corporation Obturateur anti-éruption rotatif
US20080060816A1 (en) * 2002-02-13 2008-03-13 Howlett Paul D Wellhead seal unit
US20100140516A1 (en) * 2008-12-10 2010-06-10 Stefan Butuc Bop packing units selectively treated with electron beam radiation and related methods
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US1942366A (en) * 1930-03-29 1934-01-02 Seamark Lewis Mervyn Cecil Casing head equipment
US3621912A (en) * 1969-12-10 1971-11-23 Exxon Production Research Co Remotely operated rotating wellhead
US20080060816A1 (en) * 2002-02-13 2008-03-13 Howlett Paul D Wellhead seal unit
US20050241833A1 (en) * 2002-10-31 2005-11-03 Bailey Thomas F Solid rubber packer for a rotating control device
US20120138366A1 (en) * 2002-10-31 2012-06-07 Weatherford/Lamb, Inc. Method for Cooling a Rotating Control Head
EP1627986A1 (fr) * 2004-08-19 2006-02-22 Sunstone Corporation Obturateur anti-éruption rotatif
US20100140516A1 (en) * 2008-12-10 2010-06-10 Stefan Butuc Bop packing units selectively treated with electron beam radiation and related methods

Cited By (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US9540898B2 (en) 2014-06-26 2017-01-10 Sunstone Technologies, Llc Annular drilling device
CN113236782B (zh) * 2021-04-29 2023-11-17 西安航天精密机电研究所 一种耐高压低摩擦的动密封结构
WO2024081547A1 (fr) * 2022-10-12 2024-04-18 Baker Hughes Oilfield Operations Llc Vanne, procédé et système

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