Patent Application
20210348450
The present invention relates to an apparatus and method relating to managed pressure drilling and in particular relates to a managed pressure drilling (MPD) integration joint comprising a rotating control device (RCD) and/or an annular seal.
When drilling for offshore hydrocarbons, some target reservoirs are located in difficult formations such as clastic, carbonate or pre-salt formations. Such formations require managed pressure drilling (MPD) in which the drill string is run through a riser and the pressure of the returning drilling fluid is controlled within the annulus between the outside of the drill string and the inner through bore of the riser.
The drilling fluid is typically pumped down the drill string and exists the bottom of the drill string through the BHA and the drill bit and returns up the annulus between the outside of the drill string and the inside of the riser. Deep water MPD systems typically include an integration joint which typically consists of three or more components all connected in line in the riser system. These three components typically comprise an annular seal within a separate tubular and an RCD located above the annular seal within its own separate tubular, where the integration joint is located in line/in series within the riser string above an MPD flow spool and below a telescopic joint. The RCD, the annular seal and the MPD flow spool along with the other components in the riser system all act together to enable closed loop drilling in deep water environments.
The RCD permits passage of the drill string through the riser but also seals around the drill string whilst permitting rotation of it thereby preventing pressurised drilling fluid from passing further up the annulus in the riser string. Accordingly, the RCD forces the returning drilling fluid to flow out of the annulus in the riser string and through goose necks provided at each side of the MPD flow spool where the goose necks are attached to drilling fluid return hoses.
Additional information and drawings regarding conventional integrated MPD systems can be read in Volume 76, Issue 10 of Offshore magazine and at the time of writing an online version is available at:—https://www.offshore-mage.com/articles/print/volume-76/issue˜10/drilling-and- completion/integrated-mpd-system-aids-drilling-operation-offshore-brazil.html
The skilled person will understand that because the different components that make up the integration joint (i.e. the RCD and the annular seal) are all located in line/series in separate tubular joints (each being around 20 feet in length) within the riser system, conventional MPD systems are relatively long/high in length and this carries the disadvantage that the MPD flow spool is relatively low compared to the moon pool of the drilling vessel in question and therefore it can be difficult for the operator to connect the drilling return fluid hoses to the goose neck outlet ports.
Moreover, because the different components that make up the integration joint (i.e. the RCD and annular seal) are all located in line/series in separate joints within the riser system and each tubular joint is connected to the next by a flange and bolting arrangement, it can be very difficult and very time consuming for an operator to change out for example one of the annular seals (e.g. if it is worn) for a new annular seal. Moreover, because the riser string needs to be broken out to enable that tubular annular seal to be removed from the string to allow for the new annulus seal to be included in the string, the operator loses the ability to control the pressure within the riser system and indeed the whole drill string must first be removed from the riser string.
US Patent Publication No. US2012/0085545 to Tarique et al discloses a bearing assembly 37 which comprises an upper stripper element 54 and a lower stripper element 52 both being provided within and run into or pulled from a rotating flow head housing 30 within a bearing assembly housing 40. Accordingly, in order to replace one of the stripper elements 54, 52, both of them within the bearing assembly housing 40 must be pulled from the RFH housing 30 and hence the riser must be taken out of active (pressurised) use whilst that occurs.
It is an object of the present invention to eliminate or ameliorate some or all of the above-noted disadvantages.
According to a first aspect of the present invention there is provided an integration joint assembly for use in drilling operations, the integration joint assembly comprising:—
an integration joint body comprising:—
a through bore;
an upper end adapted for connection with an upper portion of a riser system; and
a lower end adapted for connection with a lower portion of a riser system;
the integration joint assembly being adapted to permit a tubular work string to pass there through such that there is an annulus created between the inner through bore of the integration joint body and the outer surface of the tubular work string;
wherein the integration joint assembly further comprises at least two sealing devices adapted in use to provide a seal within the said annulus;
wherein the said at least two sealing devices and the integration joint body are adapted such that the said at least two sealing devices are capable of being located within the through bore of the integration joint body;
wherein, each of the said at least two sealing devices are capable of being locked within the through bore by at least two locking devices and wherein each of the at least two sealing devices comprise their own respective locking device; and
wherein each of the said at least two sealing devices can be separately locked and unlocked as required by actuation of their own respective locking device in such a manner to permit one of the sealing devices to be locked within the through bore and at least one of the at least two sealing devices to be run into and/or retrieved from the through bore of the integration joint body.
According to a second aspect of the present invention there is provided a method of drilling comprising the step of:—
installing an integration joint body according to the first aspect of the present invention in a riser string and running a tubular work string through the through bore thereof.
Preferably the integration joint assembly is for use in managed pressure drilling operations and typically the tubular work string is a drill string.
Preferably, each of the said at least two sealing devices comprises a housing and a seal mounted within said housing, and more preferably, each of the said at least two sealing devices comprises its own respective housing.
Typically, each of said at least two sealing devices comprises a housing and at least one seal mounted within said housing.
Preferably, at least one of said at least two sealing devices comprises a housing and two seals rotatably mounted within said housing by a respective bearing mechanism.
Typically, each of the said at least two sealing devices is in the form of a cartridge assembly and preferably, each of the said at least two sealing devices comprises a retrieval means to permit running in and/or retrieval of the respective each of the said at least two sealing devices.
Preferably, each housing comprises a locking means into which a respective locking device can engage in order to lock said housing of said respective sealing device within the through bore of the integration joint body. Said locking means may comprise a slot, groove or recess into which a locking device such as a locking dog may be inserted.
Preferably, each said locking device is mounted on the integration joint. Preferably, each said locking device comprises one or more radially moveable dog members which can be moved radially inwardly to projecting inwardly from the inner diameter of the integration joint body and more preferably can be moved radially inwardly to projecting inwardly from the inner diameter of the integration joint body into the said locking means of the respective sealing device. Typically, each said locking device can be actuated between a radially inwardly projecting configuration and a retracted configuration such that they do not project into said locking means of the respective sealing device. Preferably, each said locking device is remotely actuatable (such as from the surface by an operator) between the radially inwardly projecting or locked configuration and the retracted or unlocked configuration, allowing for remote activation of each of the locking devices by the operator.
Preferably the said at least two sealing devices are adapted to be located co-axially within the through bore of the integration joint body and more preferably the longitudinal length of the integration joint body is longer than the combined longitudinal length of the said at least two sealing devices and more preferably the inner diameter of the integration joint body is greater than the outer diameter of each of the said at least two sealing devices such that the said at least two sealing devices are adapted to be wholly located co-axially within the integration joint body and most preferably the said at least two sealing devices are adapted to be wholly located co-axially within the through bore of the integration joint body.
Preferably, the said at least two sealing devices comprise:—
a rotation control device (RCD); and
at least one annular seal device;
wherein said at least two sealing devices are adapted to be located within the through bore of the integration joint body. Preferably, the integration joint body is adapted to be able to house both of a rotation control device (RCD) and two said annular seal devices within its through bore, preferably in series/in line along its longitudinal length.
Preferably, at least one of the rotation control device and the annular seal device can be:—
i) run into the through bore of the integration body, typically through an upper portion of the riser string which typically includes a telescopic joint; and
ii) locked to the integration joint body within the through bore of the integration joint body.
Preferably at least one of the rotation control device and the annular seal device are capable of being unlocked from and more preferably retrieved from the through bore of the integration joint body, typically by pulling it upwards through the through bore of the integration joint body and further pulling it upwards through the through bore of the upper portion of the riser system (which may include the telescopic joint).
Preferably the rotation control device is arranged to be located above the annular seal device within the through bore of the integration joint body.
Preferably there are two annular seal devices and more preferably there is an upper annular seal device and a lower annular seal device.
The rotation control device may be retrieved and run into the through bore on its own by a running/retrieval tool or alternatively, may be retrieved and run into the through bore with at least one of the annular sealing devices.
One or both of the rotation control device and the at least one annular seal device may be located within the through bore of and locked to the integration joint body when the integration joint body is installed within the riser string; or
one or both of the rotation control device and the at least one annular seal device may be run into the through bore of the integration body through the through bore of an upper portion of the riser string (which could include the telescopic joint) and be locked to the integration joint body within the through bore of the integration joint body after the integration joint body has been installed within riser string.
Typically, suitable seals such as (but not limited to) O-ring seals, pressure activated seals or mechanically activated seals are provided to act between the outer surface of the RCD and the inner through bore of the integration joint body. Preferably said seals are provided on and/or around the outer circumferential surface of the RCD such that they act to seal the gap between the outer surface of the RCD and the inner through bore of the integration joint body.
Additionally, further suitable seals such as (but not limited to) O-ring, pressure activated seals or mechanically activated seals are typically provided to act between the outer surface of the said at least one annular seal and the inner through bore of the integration joint body. Preferably said seals are provided on and/or around the outer circumferential surface of the said at least one annular seal such that they act to seal the gap between the outer surface of the said at least one annular seal and the inner through bore of the integration joint body.
Typically, suitable seals such as (but not limited to) O-ring, pressure activated seals or mechanically activated seals are provided to act between the adjoining ends of the RCD and the said at least one annular seal.
Preferably the integration joint body comprises a seat or other formation formed on its inner through bore preferably at a location on its inner diameter and which prevents the rotation control device and the one or more annular seal devices from moving any lower through the integration joint body than said seat. Typically, the said seat is a formation formed on the inner diameter of the integration joint body and more preferably said formation comprises a narrower inner diameter load bearing shoulder than the outer diameter of at least a portion of the rotation control device and the one or more annular seal devices such that the said portion seats upon said shoulder and thus any further downward movement of the rotation control device and the one or more annular seal devices is arrested. Typically, the said formation comprises a narrower inner diameter load bearing shoulder than the outer diameter of at least a portion of a lowermost annular seal device. Alternatively, said seat or other formation comprises one or more radially moveable dog members which can be moved radially inwardly to provide a shoulder projecting inwardly from the inner diameter of the integration joint body for the said annular devices to seat upon in order to prevent the rotation control device and the one or more annular seal devices from moving any lower through the integration joint body than said shoulder or seat.
Typically, the RCD comprises an RCD body member and at least one and preferably two seals which more preferably are rotatable with respect to the RCD body member. Typically, the RCD further comprises a bearing to couple each respective seal to the RCD body member such that the said each respective seal is rotatable on the bearing with respect to the stationary RCD body member such that the said each respective seal seals against and is rotatable with the drill string which passes through the through bore of the integration joint body. Preferably the RCD comprises a pair of longitudinally spaced apart rotatable seals such that the RCD comprises an in use upper most rotatable seal and a lowermost rotatable seal. Preferably each of the upper and lower rotatable seals is formed from a resilient material such as rubber or polyurethane and has an inner diameter which is a friction fit or comprises a smaller inner diameter that the outer diameter of the drill string such that each of the upper and lower rotatable seals elastically stretches to accommodate the drill string and seals against the outer surface of the drill string such that it does not permit drilling fluid located in the annulus to pass through the through bore of the RCD in the upwards direction from downhole to up-hole.
Typically, each of the said annular seals comprises an in use de-energised or deflated inner diameter which is greater than the outer diameter of the drill string which passes there through such that when each of the said annular seals in use is de-energised it allows the free movement of the drill string there through and therefore does not impede the movement there through and therefore does not seal against the outer diameter of the drill string.
In addition, each of the said annular seals typically comprises an in use energised or inflated inner diameter which is smaller than the outer diameter of the drill string which passes there through such that when each of the said annular seals in use is energised it seals against the outer diameter of the drill string and therefore does not permit drilling fluid located in the annulus to pass through the through bore of the annular seal in the upwards direction from downhole to up-hole. Preferably each annular seal can be selectively energised or de-energised by the respective introduction or removal of fluid from a cavity in fluid communication with a surface of the said annular seal and more preferably said cavity is in fluid communication with an outer surface of the said annular seal such that when fluid is pumped into said cavity, the said annular seal is forced inwards into contact with tubular work string passing through the integration joint body to thereby form a seal in the annulus between the outer surface of the tubular work string and the inner through bore of the integration joint body.
Preferably, the locking devices are configured such that in use, in the locked configuration, the respective sealing device cannot move relative to the integration joint body and in the unlocked configuration the respective sealing device can move relative to the integration joint body. This provides for a locking system wherein when the respective locking device is moved from the unlocked configuration to the locked configuration the respective sealing device can move relative to the integration joint body.
The embodiments of the present invention have many advantages including great flexibility due to the modular nature of the sealing devices and the skilled person will understand that the RCD may be omitted if the riser system in question requires to be run in a conventional mode (not managed pressure drilling) but be able to maintain the ability to operate as a gas handling joint.
Embodiments of the present invention have the great advantage that the riser string does not need to be pulled up and taken apart in order to replace any one or more than one of the rotation control device and the at least one annular seal device because they can be run into and retrieved from the through bore of the integration joint body.
The accompanying drawings illustrate presently exemplary embodiments of the disclosure and together with the general description given above and the detailed description of the embodiments given below, serve to explain, by way of example, the principles of the disclosure.
In the description that follows, like parts are marked throughout the specification and drawings with the same reference numerals, respectively. The drawings are not necessarily to scale. Certain features of the invention may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in the interest of clarity and conciseness. The present invention is susceptible to embodiments of different forms. Specific embodiments of the present invention are shown in the drawings and herein will be described in detail, with the understanding that the present disclosure is to be considered an exemplification of the principles of the invention and is not intended to limit the invention to that illustrated and described herein. It is to be fully recognized that the different teachings of the embodiments discussed below may be employed separately or in any suitable combination to produce the desired results.
The following definitions will be followed in the specification. As used herein, the term “wellbore” refers to a wellbore or borehole being provided or drilled in a manner known to those skilled in the art. The wellbore may be ‘open hole’ or ‘cased’, being lined with a tubular string. Reference to up or down will be made for purposes of description with the terms “above”, “up”, “upward”, “upper” or “upstream” meaning away from the bottom of the wellbore along the longitudinal axis of a work string toward the surface and “below”, “down”, “downward”, “lower” or “downstream” meaning toward the bottom of the wellbore along the longitudinal axis of the work string and away from the surface and deeper into the well, whether the well being referred to is a conventional vertical well or a deviated well and therefore includes the typical situation where a rig is above a wellhead and the well extends down from the wellhead into the formation, but also horizontal wells where the formation may not necessarily be below the wellhead. Similarly, ‘work string’ refers to any tubular arrangement for conveying fluids and/or tools from a surface into a wellbore. In the present invention, drill string is the preferred work string.
The various aspects of the present invention can be practiced alone or in combination with one or more of the other aspects, as will be appreciated by those skilled in the relevant arts. The various aspects of the invention can optionally be provided in combination with one or more of the optional features of the other aspects of the invention. Also, optional features described in relation to one embodiment can typically be combined alone or together with other features in different embodiments of the invention. Additionally, any feature disclosed in the specification can be combined alone or collectively with other features in the specification to form an invention.
Various embodiments and aspects of the invention will now be described in detail with reference to the accompanying figures. Still other aspects, features and advantages of the present invention are readily apparent from the entire description thereof, including the figures, which illustrates a number of exemplary embodiments and aspects and implementations. The invention is also capable of other and different embodiments and aspects and its several details can be modified in various respects, all without departing from the spirit and scope of the present invention.
Any discussion of documents, acts, materials, devices, articles and the like is included in the specification solely for the purpose of providing a context for the present invention. It is not suggested or represented that any or all of these matters formed part of the prior art base or were common general knowledge in the field relevant to the present invention.
Accordingly, the drawings and descriptions are to be regarded as illustrative in nature and not as restrictive. Furthermore, the terminology and phraseology used herein is solely used for descriptive purposes and should not be construed as limiting in scope. Language such as “including”, “comprising”, “having”, “containing” or “involving” and variations thereof, is intended to be broad and encompass the subject matter listed thereafter, equivalents and additional subject matter not recited and is not intended to exclude other additives, components, integers or steps. In this disclosure, whenever a composition, an element or a group of elements is preceded with the transitional phrase “comprising”, it is understood that we also contemplate the same composition, element or group of elements with transitional phrases “consisting essentially of”, “consisting”, “selected from the group of consisting of”, “including” or “is” preceding the recitation of the composition, element or group of elements and vice versa. In this disclosure, the words “typically” or “optionally” are to be understood as being intended to indicate optional or non-essential features of the invention which are present in certain examples but which can be omitted in others without departing from the scope of the invention.
All numerical values in this disclosure are understood as being modified by “about”. All singular forms of elements, or any other components described herein including (without limitations) components of the assembly are understood to include plural forms thereof and vice.
Embodiments of the present invention will now be described, by way of example only and with reference to the accompanying drawings, in which:—
Moreover, the integration joint body 10 comprises a through bore 16 having an inner through bore surface 18, an outer diameter surface 20 and a side wall 22 such that the integration joint body 10 is generally tubular along its longitudinal length.
The side wall 22 is generally sealed along its length such that pressurised fluids located within the integration joint body 10 and thus the rest of the riser string are safely contained by and within the side wall 22 of the integration joint body 10.
However, if MPD is required then the system shown in
Next, an operator attaches at least two and more preferably three sealing devices in the form of a lower packer cartridge assembly 100, with an upper packer cartridge assembly 200 located above the lower packer cartridge assembly 100 and also attaches an RCD bearing assembly 300 just above the upper packer cartridge assembly 200 to the running tool 54, such that the running tool 54 (and the drill string 50 located below it) are lowered into the through bore 16 of the integration joint body 10 such that the lower packer cartridge assembly 100, upper packer cartridge assembly 200 and RCD bearing assembly 300 are run into the through bore of the telescopic joint and rest of upper portion of the riser system and then into the through bore of the integration joint body 10 in order to form the integration joint assembly 5 in accordance with the present invention and this point in the operation is shown in
The lower packer cartridge assembly 100 is shown in more detail in
The lower packer cartridge body 104 is further provided with a means of running in and/or retrieval in the form of a retrieval profile 110 formed therein on the inner through bore surface 105 thereof and which in use can be latched into by the running tool 54 having a suitably configured and co-operating retrieval profile 56 (seen in
The lower packer cartridge assembly 100 further comprises a lock in the form of a groove 114 formed circumferentially around the outer surface of the lower packer cartridge body 104 where, in use, an operator can extend one or more keys in the form of lower packer cartridge locking dogs 60 through the side wall 22 of the integration joint body 10 into the groove 114 in order to longitudinally lock the lower packer cartridge assembly 100 in place at the lower end within the through bore 16 of the integration joint body 10 as will be described subsequently.
Lower packer cartridge seals 109 (see
The upper packer cartridge assembly 200 is broadly speaking relatively similar to the lower packer cartridge assembly 100 and thus similar components and features of the upper packer cartridge assembly 200 to those of the lower packer cartridge assembly 100 are indicated with the same reference numeral but with the addition of 100.
In general terms though, the upper packer cartridge assembly 200 is slightly longer along the longitudinal axis than the lower packer cartridge assembly 100 and the retrieval profile 210 is formed on the inner through bore surface 207 of the upper packer end cap 206 (instead of being formed on the inner through bore surface 205). In addition, the very lower end of the upper packer end cap 206 is provided with a spigot 216 which further comprises seals such as O-ring seals 217 formed about its outer circumferential surface and which is arranged to project into and therefore seal against (by means of the seals 217) against the inner surface of socket joint 118 provided at the upper end of the lower packer cartridge body 104.
Upper packer cartridge seals 209 (see
The RCD bearing assembly 300 is best seen in
The RCD bearing assembly 300 further comprises an upper RCD seal 304 arranged within a recess 303 within the RCD bearing body 306 where the upper RCD seal 304 is further connected to the RCD bearing body 306 at its upper end by means of a rotatable bearing 308 such that the upper RCD seal 304 can rotate about the longitudinal axis 307 with respect to the stationary RCD bearing body 306.
The RCD bearing assembly 300 further comprises a lock in the form of a groove or recess 314 formed circumferentially about or around the outer surface of the RCD bearing body 306 where, in use, an operator can extend one or more keys in the form of RCD assembly locking dogs 68 through the side wall 27 of the integration joint body 10 into the groove 314 in order to longitudinally lock the RCD bearing assembly 300 in place at the upper end of the through bore 16 within the integration joint body 10 as will be described subsequently.
The RCD bearing assembly 300 is further provided with a means of running in and/or retrieval in the form of a tapered retrieval surface 310 (best seen in
RCD bearing assembly seals 317 are provided on the outer diameter of the RCD bearing assembly 300 to seal against the inner diameter 18 of the integration joint body 10 to seal the annulus 24 between the outer diameter of the RCD bearing assembly 300 and the inner diameter 18 of the integration joint body 10 and thereby prevent any fluid in the riser string from leaking past the outer surface of the RCD bearing assembly 300.
In the embodiment of the invention described with reference to
Once the lower seat 120 of the lower packer cartridge assembly 100 has landed on the load shoulder 26, the integration joint assembly 5 is complete in that it now comprises the integration joint body 10 and within its through bore are now located the lower and upper packer cartridge assemblies 100, 200 and the RCD bearing assembly 300.
Indeed, the seals 109, 209 on the outer diameter of the upper 200 and lower 100 packer cartridge assemblies are engaged on the inner diameter 18 of the integration joint body 10 and seals 317 provided on the outer diameter of the RCD bearing assembly 300 are also engaged on the inner diameter 18 of the integration joint body 10 in order to seal the annulus there between.
The upper RCD seal 304 and lower RCD seal 302 are generally formed of a resilient material such as rubber or polyurethane and in use will act as a relatively tight sealing ring through which the operator (when conducting MPD operations) will physically push the drill pipe string in order to have the drill pipe string pass through the RCD bearing assembly 300. Accordingly, the lower RCD seal 302 and upper RCD seal 304 are adapted to stretch in the radially outwards direction as the drill pipe string 50 is pushed through them and indeed are adapted to always seal via their respective inner surfaces to the outer surface of the drill pipe string up to the point where the drill pipe string is removed from within their through bore or ultimately up until the point that the upper or lower RCD seals 302, 304 fail. Moreover, because each of the upper 304 and lower 302 RCD seals are provided with their respective bearings 305, 308, the lower 302 and upper 304 RCD seals will rotate with the drill pipe string when it rotates relative to the stationary riser string and integration joint body 10.
In order to prepare for MPD, the operator will lock the lower packer cartridge assembly 100, upper packer cartridge assembly 200 and RCD bearing assembly 300 in the position as shown in
Accordingly, the integration joint assembly 5 is now in the configuration as shown in
The operator then remotely actuates the upper packer cartridge locking dogs 68 in order to retract them from engagement with the groove 214 such that the upper packer cartridge assembly 200 is no longer locked in place within the integration joint body 10 and this stage is shown in
If the operator wishes to remove the lower packer cartridge assembly 100, the retrieval tool 54 is once again run down into the integration joint body 10 on the drill string 50 at the top thereof such that it is run through the telescopic joint (not shown) and into the integration joint body 10. The retrieval tool 54 is moved sufficiently downwards such that its retrieval profile 56 is moved into alignment with the retrieval profile 110 formed by the grooves provided on the inner surface of the through bore 105 of the lower packer cartridge body 104 until the respective profiles 56, 110 are in locking engagement with one another. It should be noted that the retrieval tool 54 and retrieval profile 56 could be the same retrieval tool 54 and retrieval profile 56 that were used to retrieve the upper packer cartridge assembly 200 although it may be that they could be different if operational requirements would find that beneficial. This point in the operation is shown in
Continued lifting of the drill pipe string and retrieval tool 54 lifts the lower packer cartridge assembly 100 out of the through bore 16 of the integration joint body 10 and through the telescopic joint (not shown) to the surface. This stage in the operation is shown in
If the operator wishes, the operator can repeat the stages shown in
In addition, embodiments of the present invention have additional flexibility in that it is possible to remove different combinations of the RCD bearing assembly 300 and the upper 200 and lower 100 packer cartridge assemblies depending upon operational requirements.
For example, the operator can decide to remove the RCD bearing assembly 300 and the upper packer cartridge assembly 200 as one unit by running the retrieval tool 54 from the surface down through the telescopic joint and into the through bore 16 of the integration joint body 10. The operator can arrange the running/retrieval tool 54 to lock into the grooved recessed profile on the inner diameter surface 205 of the upper packer cartridge assembly 200 and this stage of the operation is shown in
The operator will then remotely unlock the RCD assembly locking dogs 68 by retracting them through the side wall 22 and will also instruct the upper packer cartridge locking dogs 64 to retract again by withdrawing them back through the side wall 22 such that the RCD bearing assembly 300 and the upper packer cartridge assembly 200 are now unlocked with respect to the integration joint body 10. It should be noted that this unlocking can be achieved whilst fully maintaining operation of the lower packer cartridge assembly 100. Moreover, the lower packer cartridge assembly 100 may be energised or de-energised during this stage as shown in
In addition, seals are provided 109, 209 on the outer diameter of the upper 200 and lower 100 packer cartridge assemblies which respectively seal on the inner diameter of the integration joint body 10 and prevent any fluid in the riser string from leaking past the respective upper 200 and lower 100 packer cartridge assemblies.
Furthermore, seals 317 are provided on the outer diameter of the RCD bearing assembly 300 and which seal on the inner diameter of the upper packer cartridge assembly 200.
Additional components and equipment can be added to embodiments of the integration joint assembly 5 as required such as auxiliary lines (e.g. choke and kill lines) etc. without departing from the present invention.
Embodiments of the present invention have the great advantage over conventional integration joints that the integration joint assembly 5 is much shorter in length than conventional integration joints and therefore, in use, the goose necks of the MPD flow spool will be much higher up the riser string and therefore are closer to the moon pool of the surface vessel thus allowing the operator much easier access to the drilling fluid return hoses that are connected to the goose necks of the MPD flow spool. In addition, whilst the integration joint assembly 5 can be and is intended for managed pressure drilling, it can additionally be used for gas handling (in which case the RCD bearing assembly 300 is not required).
It should also be noted that where the integration joint assembly 5 is not used in a floating rig application, the integration joint assembly 5 would not need to be located in line below the telescopic joint but for floating rig applications such as a semi-submersible or drill ship, the integration joint assembly 5 is typically located within the riser string below the telescopic joint (not shown).
Embodiments of the present invention also have the advantage that instead of pressurised hydraulic fluid being pumped into the cavity behind each of the lower 102 and upper 202 annular packer seals, pressurised gas could instead be pumped into that cavity via the respective hydraulic port 108A, 208A from the respective lower 108B and upper 208B packer hydraulic fluid extend ports.
The lower 100 and upper 200 packer cartridge assemblies can be used for a wide range of scenarios such as, but not limited to:—
sealing on the drill pipe string 50 when the RCD bearing assembly 300 seals 302, 304 fail;
as a back up to the RCD bearing assembly 300;
for stripping drill pipe from the drill pipe string 50 when removing/replacing the RCD bearing assembly 300; or
for gas handling.
Accordingly, embodiments of the present invention have the advantage that the whole riser string does not need to be decommissioned out of active (i.e. pressurised) service if the RCD bearing assembly 300 needs to be replaced because the lower 100 and/or upper 200 packer cartridge assemblies can be actuated to seal their respective seal against the drill pipe string 50, unlike for example the prior art replaceable rotatable bearing system 40 shown in US Patent Publication No. US2012/0085545.
Embodiments of the present invention have the further advantage that the upper 202 and lower 102 annular packer seals are housed within separate cartridges 200, 100 and these cartridges 100, 200 are retrievable separately or can be retrieved together from the through bore 16. In addition, the upper packer cartridge 200 is additionally designed to have the RCD bearing assembly 300 landed and housed thereon and this therefore allows the RCD bearing assembly 300 to land and seal on the upper packer cartridge assembly 200 and this feature also allows both the upper packer cartridge assembly 200 and RCD bearing assembly 300 to be run/retrieved from the through bore 16 through the riser string as one unit if desired.
Embodiments of the present invention have the further advantage that the upper and lower packer cartridge assemblies 200, 100 provide redundancy and the ability to change the upper packer cartridge assembly 200 whilst maintaining the lower packer assembly 100 functionality. It would be possible however that modifications could be made to the integration joint assembly 5 in order to have further packer seals or indeed just one packer seal such as that 102 contained in the lower packer cartridge assembly 100.
The RCD bearing assembly 300 can be retrieved from the through bore 16 whilst maintaining the functionality of both the lower 100 and upper 200 packer cartridge assemblies and the cartridge assemblies 100, 200 can remain locked in place in the through bore 16 during removal and replacement of the RCD bearing assembly 300.
The embodiments of the present invention have the further advantage that the upper packer cartridge 200 can be retrieved whilst maintaining the functionality of the lower packer cartridge assembly 100 which can remain locked in place within the through bore 16 of the integration joint body 10. In addition, the upper 200 and lower 100 packer cartridge assemblies can be retrieved collectively if desired or alternatively the upper packer cartridge assembly 200 can be retrieved on its own by the operator.
The locking dogs 60, 64, 68 are incorporated into the integration joint body 10 to independently lock the RCD bearing assembly 300, upper packer cartridge assembly 200 and lower packer cartridge assembly 100 and these locking dogs, 60, 64, 68 are hydraulically driven and extend radially inwards to lock on to their respective locking grooves 314 in the RCD bearing assembly 300 and groove 214 in the upper packer cartridge assembly and locking groove 114 in the lower packer cartridge assembly 100. Moreover, the locking dogs 60, 64, 68 can function independently or in any combination thereof and thus permit independent locking and unlocking for each of the RCD bearing assembly 300, upper packer cartridge assembly 200 and lower packer cartridge assembly 100.
In addition, the embodiments of the present invention have the advantage that the upper packer cartridge assembly 200 lands on the lower packer cartridge assembly 100 when being installed separately and the upper packer cartridge assembly 200 comprises seals 217 which seal against the inner surface of the socket joint 118 once landed in the lower packer cartridge assembly 100.
Embodiments of the present invention have the yet further and important advantage that any one, two or three of the RCD bearing assembly 300, upper 200 and lower 100 packer cartridge assemblies can be replaced by running them through the through bore of the riser string from and into the through bore 16 without having to dismantle the riser string and that advantage will provide very significant benefits to an operator.
Moreover, the ability of each set of locking dogs 60, 64, 68 to be operated independently from one another in order to provide an independent and separable lockable ability for each of the:—lower packer cartridge assembly 100;
upper packer cartridge assembly 200; and
RCD bearing assembly 300
means that each assembly 100, 200, 300 can be separably lockable and this provides the further advantage that one or two of them e.g. the lower packer cartridge assembly 100 on its own or both the lower 100 and upper 200 packer cartridge assemblies can be locked in placed and can therefore provide sealing capability whilst e.g. the upper packer cartridge assembly 200 and/or the RCD bearing assembly 300 can be retrieved and replaced if needs be from the through bore 16 of the integration joint body 10.
Modifications and improvements may be made to the embodiments herein before described without departing from the scope of the invention.
For example, the RCD bearing assembly 300 could be modified to only have one of the upper 304 or lower 302 RCD seals but it is much preferred to have two such seals for redundancy purposes and indeed many jurisdictions around the world require two such seals due to the potentially high pressure of the drilling fluid to be sealed.
In addition, the locking dogs 60, 64, 68 could be replaced by any suitable locking arrangement although a remote locking arrangement would be preferred.
| Number | Date | Country | Kind |
|---|---|---|---|
| 1818114.9 | Nov 2018 | GB | national |
| Filing Document | Filing Date | Country | Kind |
|---|---|---|---|
| PCT/GB2019/053134 | 11/5/2019 | WO | 00 |
