BACKGROUND
Exploration for, location of, and extraction of subterranean fluids, including hydrocarbon fluids, typically involves drilling operations to create a well. Drilling operations, particularly drilling operations involving rotary drilling, often utilize drilling fluids, also called muds, for a variety of reasons including lubrication, removal of cuttings and other matter created during the drilling process, and to provide sufficient pressure to ensure that fluids located in subterranean reservoirs do not enter the borehole, or wellbore, and travel to the surface of the earth. Fluids located in subterranean reservoirs are under pressure from the overburden of the earth formation above them. Specialized equipment is used to provide control of all fluids used or encountered in the drilling of a well.
Conventionally, well pressure control equipment may include a blowout preventer (BOP) stack that sits atop of a wellhead. The BOP stack may include ram BOP(s) and an annular BOP. An annular preventer is a large valve used to control wellbore fluids. In this type of valve, the sealing element resembles a large rubber doughnut that is mechanically squeezed inward to seal on either pipe (drill collar, drillpipe, casing, or tubing) or the openhole. The ability to seal on a variety of pipe sizes is one advantage the annular preventer has over the ram blowout preventer. Most BOP stacks contain at least one annular preventer at the top of the BOP stack, and one or more ram-type preventers below.
Above the annular BOP is often a managed pressure drilling/underbalance drilling rotating control device (RCD)/rotating head. The RCD/rotating head is a pressure-control device used during drilling for the purpose of making a seal around the drillstring while the drillstring rotates. Essentially, the RCD/rotating head is a diverter with holding pressure capability. This device is intended to contain hydrocarbons or other wellbore fluids and prevent their release to the atmosphere by diverting flow through an outlet below the sealing element.
SUMMARY OF DISCLOSURE
In one or more embodiments, a rotating annular preventer may include a body; at least one seal housed within the body and configured to seal against a tubular extending through the rotating annular preventer by actuation of a piston, wherein the at least one seal comprises at least one rotatable seal; and an outlet in the side of the body to divert fluid from an annulus surrounding the tubular, wherein the outlet is located axially below the piston.
In one or more embodiments, a method for using a rotating annular preventer may include placing a tubular in the rotating annular preventer about an central axis of the rotating annular preventer; sealing off the annulus around the tubular with the rotating annular preventer by actuating a first seal around the tubular by a piston and/or rotating a second seal sealingly engaged with the tubular as the tubular is rotated, the rotating annular preventer being configured to do both; and opening a valve to redirect a fluid in the annular around the tubular out an outlet flow line that is below the first seal being actuated by the piston.
This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.
BRIEF DESCRIPTION OF DRAWINGS
FIG. 1 illustrates a schematic view of a rotating annular preventer according to one or more embodiments of the present disclosure.
FIG. 2 illustrates a schematic view of a rotating annular preventer according to one or more embodiments of the present disclosure.
FIG. 3 illustrates a schematic view of a rotating annular preventer according to one or more embodiments of the present disclosure.
FIG. 4 illustrates a schematic view of a rotating annular preventer according to one or more embodiments of the present disclosure
FIG. 5 illustrates a schematic view of an apparatus of a rotating annular preventer according to one or more embodiments of the present disclosure.
FIG. 6 illustrates a side view of an apparatus of a rotating annular preventer according to one or more embodiments of the present disclosure.
FIG. 7 illustrates a cross-sectional view of an apparatus of a rotating annular preventer according to one or more embodiments of the present disclosure.
FIG. 8 illustrates a cross-sectional view of an apparatus of a rotating annular preventer according to one or more embodiments of the present disclosure.
DETAILED DESCRIPTION
Embodiments of the present disclosure are described below in detail with reference to the accompanying figures. Like elements in the various figures may be denoted by like reference numerals for consistency. Further, in the following detailed description, numerous specific details are set forth in order to provide a more thorough understanding of the claimed subject matter. However, it will be apparent to one having ordinary skill in the art that the embodiments described may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description.
While annular BOPs and rotating control device (RCD)/rotating heads are conventionally two separate pieces of equipment used in control of an oil well, embodiments of the present disclosure may allow for the integration of the functionalities provided by the two together into a single body/device. Such integrated device may be referred to as a rotating annular preventer (RAP). Conventionally, an annular preventer is mainly used in well control scenarios to strip in and out the tubulars; however, a major drawback of the annular preventer, in the field today, is the inability to divert fluid, necessitating the use of a choke below the annular preventer. Further, conventionally a rotating head is used in drilling in under or at or over balanced scenarios or under managed pressure drilling, where the fluid is maintained within a pressurized system, rather than being open to the atmosphere. The RCD/rotating head seals against the tubular as it rotates within the device (during drilling) and diverts the returned fluid from the annulus to a MPD manifold. Thus, in one or more embodiments, a rotating annular preventer is an integrated managed pressure drilling/underbalanced drilling rotating control device/rotating head and well control annular blowout preventer. The integration may take various forms, including the use of a single body/bonnet and/or integration of internal parts.
By integrating the functionalities into a single device, in one or more embodiments, the RAP of the present disclosure may divert fluid, seal off the annulus while tubulars are moving up and downwards and/or rotating, seal off the wellbore when there are no tubulars in it, and/or strip in and out the tubulars in well control situation. The RAP can be used on and off while drilling through different formations and depths when is needed, or tripping in and out or stripping in and out while securing the well. The RAP as a single piece equipment may be installed, for example, at the top of the BOP stack, in the place of a conventional annular preventer, with a bell nipple being installed at the top of the RAP.
Now referring to FIG. 1, the integrated functionality of a rotating annular preventer according to one or more embodiments is shown. In FIG. 1, a tubular 100 is positioned about a central axis 101. Those skilled in the art would appreciate how the tubular 100 may be any string of tubulars that connect end-to-end such as, but not limited to, drill pipe string. The tubular 100 extends into a wellbore through an annular preventer 102. Annular preventer 102 includes an annular preventer (AP) seal 103 or packing element that is positioned about the central axis 101. Adjacent to a bottom or outer radial surface of AP seal 103 is a piston 104 having a wedge face which interfaces/abuts the AP seal 103. Further, FIG. 1 illustrates that the AP 103 seal and the piston 104 both have a triangular cross-section; however, it may be understood that the AP seal 103 may have any geometry suitable for tubular sealing and actuation, such as by a corresponding face of the piston 104. The AP seal 103 is configured to close around tubular 100 when piston 104 moves axially upwards, thus sealing off an annulus between tubular 100 and wellbore (not shown). Further, in one or more embodiments, AP seal 103 may seal upon itself (without a tubular 100 being present), sealing off the wellbore from the environment. AP seal may be selected to have durability for long lasting operations under harsh physical and chemical conditions, including exposure to sharp edges of tubulars, H2S, CO2, corrosive materials, heat, high velocity stripping, tong marks on tool joints, rough hard banding, and/or various mud types and additives. Further, AP seal 103 may also seal against a variety of sizes and shapes of tubulars, collars, tool joints, etc., as well as on itself in scenarios where no tubular is present in the well. In one or more embodiments, AP seal or packing element 103 may include an elastomeric material having a plurality of supporting metallic inserts or particles molded or otherwise provided therein.
Piston 104 may be hydraulically actuated to engage and disengage the AP seal 103, thereby opening and closing the annular preventer 102. A wellbore pressure 105 may optionally be used in conjunction with the hydraulically actuated piston 104 to close the AP seal 103 around the tubular 100. The wellbore pressure 105 can be applied directly or indirectly to the hydraulically actuated piston 104 to help close the AP seal 103 around the tubular 100 by any passageway or fluid communication between the annulus and the piston 104. By hydraulically actuating piston 104, piston 104 is not dependent on the wellbore pressure 105, thus allowing the piston 104 to engage and disengage the AP seal 103 under any wellbore pressure 105. Additionally, an outlet flow line 106 is disposed below AP seal 103, such as at a bottom of the annular preventer 102, to allow a flow of wellbore fluid out of the annular preventer 102. Once an AP seal 103 seals around tubular 100 and valve 107 is opened, the outlet flow line 106 will divert wellbore fluid from the annulus (not shown) since the AP seal 103 has closed the annular flowpath around tubular 100. Additionally, the valve 107 may be a hydraulically remote valve (HCR) to open and close the valve hydraulically and remotely. Furthermore, a check valve 111 or a one way valve, to prevent reverse flow of the fluid, may be used in conjunction with the valve 107. As seen by FIG. 1, the check valve 111 is positioned near the valve 107 on an opposite end of the outlet flow line 106. Further, it is also envisioned that the check valve 111 may also be placed between outlet flow line 106 and valve 107, or there may be a plurality of check valves 111, such as on both sides of the valve 107. Further, in the illustrated embodiment, piston 104 is hydraulically actuated; however, the wellbore pressure 105 may enhance the sealing of the AP seal 103 with the tubular 100. The hydraulic actuation may be considered an active sealing system, whereas use of wellbore pressure alone is a passive sealing system. Embodiments using both hydraulic actuation in combination with the wellbore pressure, as illustrated in FIG. 1, may be referred to as a combination sealing system.
Further, a bearing assembly 108 is disposed on the piston 104 at an outer radial surface thereof. The bearing assembly 108 allows for the rotation of piston 104 (and AP seal 103 via its engagement with piston 104) within the annular preventer 102, unlike conventional annular BOPs. While not specifically illustrated, it is envisioned that heat generated by the bearing assembly 108 may be transferred therefrom with the use of a circulating hydraulic lubricant oil system. The rotation of the AP seal 103 and piston 104 may result from rotation of tubular 100 sealed at an inner surface of AP seal 103. Thus, as tubular 100 rotates, the sealing engagement between tubular 100 and AP seal 103 and the engagement between AP seal 103 and piston 104 causes the AP seal 103 and piston 104 to rotate along with tubular 100. Thus, actuation of the piston 104 may cause seal 103 to seal against the tubular either in well control situations or when it is desired to drill under managed pressure. Additionally, at least one or more hydraulic lines (not shown) are coupled to the piston 104 for actuation thereof. In one or more embodiments, the piston 104 may have one hydraulic line (not shown) configured to disengage the piston 104 from the AP seal 103 and another hydraulic line (not shown) to engage the piston 104 to the AP seal 103.
While FIG. 1 shows the bearing assembly located radially outside of the piston 104 (and AP seal 103), the present disclosure is not so limited. Rather, in the embodiment illustrated in FIG. 2, a bearing assembly 109 is disposed in between the AP seal 103 and the piston 104. Further, as with bearing assembly 108 described above, bearing assembly 109 may be provided with a circulating hydraulic lubrication oil system (not shown) to transfer heat away from bearing assembly 108 during use/rotation of seal 103. Specifically, as a tubular 100 rotates within annular preventer 102, if piston 104 has been actuated (hydraulically or by wellbore pressure 105 or by a combination thereof), AP seal 103 will rotate within piston 104 based on the sealing engagement of AP seal 103 and tubular 100.
Further, as described above, annular preventer 102 also includes an outlet flow line 106 that, upon opening of valve 107, may divert wellbore fluid from the annulus upon sealing engagement of AP seal 103 with tubular 100 (or itself if no tubular is present). Additionally, a check valve 111 or a one way valve, to prevent reverse flow of the fluid, may be used in conjunction with the valve 107. As seen by FIG. 2, the check valve 111 is positioned near the valve 107 on an opposite end of the outlet flow line 106. Further, it is also envisioned that the check valve 111 may also be placed between outlet flow line 106 and valve 107, or there may be a plurality of check valves 111, such as on both sides of the valve 107. Furthermore, FIG. 3 shows another embodiment, where bearing assembly 108 is disposed on a radially outer surface of piston 104 and a second bearing assembly 109 is disposed between the AP seal 103 and the piston 104, both of which may include lubrication systems for transferring heat away therefrom. Thus, as a tubular 100 rotates within annular preventer 102, if piston 104 has been actuated (hydraulically or by wellbore pressure 105 or by a combination thereof), AP seal 103 will rotate with or within piston 104 based on the sealing engagement of AP seal 103 and tubular 100. Further, as described above, annular preventer 102 also includes an outlet flow line 106 that, upon opening of valve 107, may divert wellbore fluid from the annulus upon sealing engagement of AP seal 103 with tubular 100. Furthermore, a check valve 111 or a one way valve, to prevent reverse flow of the fluid, may be used in conjunction with the valve 107. As seen by FIG. 3, the check valve 111 is positioned near the valve 107 on an opposite end of the outlet flow line 106. Further, it is also envisioned that the check valve 111 may also be placed between outlet flow line 106 and valve 107, or there may be a plurality of check valves 111, such as on both sides of the valve 107.
Referring now to FIG. 4, an embodiment illustrating an example implementation of the annular preventer of the present disclosure. For example annular preventer 102 has a body 110 housing AP seal 103 that can seal against a tubular (not shown) extending through a bore of the annular preventer 102 or in some embodiments, can form a seal upon itself (when no tubular is present) to seal off the wellbore. The sealing by AP seal 103 is actuated by a wedge piston 104 (which may be hydraulically actuated by hydraulic fluid pumped in chambers adjacent to the wedge piston 104) and/or passively achieved through the wellbore pressure. AP seal 103 may rotated within body 110, such as when sealed against a tubular (not shown) that is rotated within the annular preventer 102. AP seal 103 may rotate, for example, due to the incorporation of a bearing assembly 108 that is on a radial outer surface of AP seal 103. It is also envisioned that a bearing assembly 108 may be omitted (in this embodiment or any of the above embodiments) and the AP seal 103 may rotate within the annular preventer based on a non-bearing assembly mechanism, such as the incorporation of a lubricant at the outer radial surface of the AP seal so that the AP seal 103 may move independently from body 110 or annular preventer 102 (such as in a rotational direction). Upon sealing of AP seal 103 (either to a tubular or on itself), fluids present in the annulus of the wellbore may flow through an outlet flow line 106 present in the body 110 to be diverted outside of the annular preventer 102 (upon opening of valve 107, which may be hydraulically or manually operated). As illustrated, outlet flow line 106 is located below AP seal 103 and is in fluid communication with the annulus via a passageway (not shown) formed in the body 110. Furthermore, a check valve 111 or a one way valve, to prevent reverse flow of the fluid, may be used in conjunction with the valve 107. As seen by FIG. 4, the check valve 111 is positioned near the valve 107 on an opposite end of the outlet flow line 106. Further, it is also envisioned that the check valve 111 may also be placed between outlet flow line 106 and valve 107, or there may be a plurality of check valves 111, such as on both sides of the valve 107. Further, while body 110 is described as being the outer housing for the internal annular preventer 102 components, it is also appreciated that the body may have multiple components, such as a body and bonnet, etc. that may be attached together to form a complete outer structure. The precise arrangement of such components is not a limitation on the present disclosure. However, it is envisioned that in one or more embodiments, all of the internal components providing the rotating annular preventer functionalities reside within a single outer “body” or structure (even if the outer structure is formed from multiple parts). In that sense, it is envisioned that the functionality of the device is not achieved without assembly of the outer structure together. In contrast, a conventional annular preventer or RCD could function independently without connection of the two together (such as by flanges).
Referring now to FIG. 5, another embodiment of an annular preventer is shown.
While the above described embodiments show a single seal (that is rotatable) in order to combine the annular BOP and RCD functionalities into a single packing element, the present disclosure is not so limited. Rather, embodiments may also use, within a single body, multiple seals (at least one of which is rotatable) and achieve a device of the present disclosure. For example, according to one or more embodiments, a rotating annular preventer 400 has functionalities for a rotating control device in an upper region 401 and an annular preventer in a lower region 402 in a single body 410. Further, while body 410 is described as being the outer housing for the internal rotating annular preventer 400 components, it is also appreciated that the body may have multiple components, such as a body and bonnet, etc. that may be attached together to form a complete outer structure. The precise arrangement of such components is not a limitation on the present disclosure. The rotating control device 401 is axially above the annular preventer 402.
Still referring to FIG. 5, the rotating control device upper region 401 may provide functionality that enables managed pressure drilling and seal against a moving tubular (rotationally and axially moving) as drilling fluid is pumped into the wellbore and returns to the surface through the annulus. Specifically, rotating control device upper region 401 includes a rotating control device (RCD) seal or packing unit 403 housed within body 410. On the outer radial surface of RCD seal 403 is a RCD bearing assembly 408, which allows for the rotation of the RCD seal 403 within the rotating control device 401. Further, as described above, heat generated by bearing assembly 408 may be transferred elsewhere by a circulating hydraulic lubricant oil system (not shown).
As a tubular 100 rotates within the rotating annular preventer 400, the RCD seal 403 will rotate based on the sealing engagement of the RCD seal 403 and the tubular 100. The engagement of RCD seal 403 with tubular 100 occurs when the annular preventer 402 (described below) is open. Specifically, RCD seal 403 engages against tubular 100 extending through a bore of the rotating annular preventer 400 due to wellbore pressure 105. Wellbore pressure 105 may be transmitted through any passageway or the like that can provide fluid communication between the annulus and RCD seal 403. Upon engaging with tubular 100, RCD seal 403 is intended to contain hydrocarbons or other wellbore fluids and prevent their release to the atmosphere. Rather, engagement of RCD seal 403 with tubular 100 will result in wellbore fluids being diverted from the annulus through the outlet flow line 106 (upon opening of valve 107) so that drilling may continue under managed pressure. Outlet flow line 106 is located towards the bottom end of body 410.
Below rotating control device upper region 401 and above outlet flow line 106 is annular preventer lower region 402, which provides well control functionality. In one or more embodiments, the annular preventer lower region 402 includes an annular preventer (AP) seal 103 that is positioned about the central axis 101 (and an optional tubular 100). When open, AP seal 103 may have an internal diameter that, at a minimum, is the same as a ram BOP stack (not shown), thereby allowing easy passage of the tubulars therethrough without any restriction. Adjacent to a bottom or outer radial surface of AP seal 103 is a piston 104 having a wedge face. Further, FIG. 5 illustrates that AP seal 103 and the piston 104 both have a triangular cross-section; however, it may be understood that the AP seal 103 may have any geometry suitable for tubular sealing and actuation, such as by a corresponding face of the piston 104. The AP seal 103 is configured to close around tubular 100 when piston 104 moves up, thus sealing off an annulus between tubular 100 and wellbore (not shown). Piston 104 may be hydraulically actuated to engage and disengage the AP seal 103, thereby opening and closing the annular preventer 402. A wellbore pressure 105 may be used in conjunction with the hydraulically actuated piston 104 to close the AP seal 103 around the tubular 100. By hydraulically actuating piston 104, piston 104 is not dependent on the wellbore pressure 105 (though, may be enhanced by wellbore pressure 105), thus allowing the piston 104 to engage and disengage the AP seal 103 under any wellbore pressure 105. Furthermore, the piston 104 can engage the AP seal 103 to seal upon itself (when no tubular is present) to seal off the wellbore. Additionally, an outlet flow line 106 is disposed below AP seal 103, such at a bottom of the annular preventer 402, to allow a flow of wellbore fluid out of the annular preventer 402. Once an AP seal 103 seals around tubular 100 and valve 107 is opened, the outlet flow line 106 will divert wellbore fluid from the annulus (not shown) since the AP seal 103 has closed the annular flowpath around tubular 100. Furthermore, a check valve 111 or a one way valve, to prevent reverse flow of the fluid, may be used in conjunction with the valve 107. As seen by FIG. 5, the check valve 111 is positioned near the valve 107 on an opposite end of the outlet flow line 106. Further, it is also envisioned that the check valve 111 may also be placed between outlet flow line 106 and valve 107, or there may be a plurality of check valves 111, such as on both sides of the valve 107. Further, in the illustrated embodiment, piston 104 is hydraulically actuated; however, the wellbore pressure 105 may enhance the sealing of the AP seal 103 with the tubular 100. As stated above, the hydraulic actuation may be considered an active sealing system, whereas use of wellbore pressure alone is a passive sealing system. As described above, the rotating control device upper region 401 uses wellbore pressure as a passive sealing system, and the annular preventer lower region 402 is an active sealing system, all within a single body 410.
Now referring to FIG. 6, according to one or more embodiments, a rotating annular preventer 600 has a body 601, which has an upper portion 602 and a lower portion 603. Furthermore, a rotating control device 610 is housed within in the upper portion 602 of body 601, and an annular preventer 611 is housed within the lower portion 603 of body 601. The rotating control device 610 and annular preventer 611 are not separate devices per se but contain distinct components that provide distinct functionality and thus are referred to as such. However, the rotating annular preventer 600 is a single device having multiple functionality all housed within a single body 601. Additionally, the lower portion 603 has an outlet flow line 604 disposed on its outer wall and a valve 605 to open and close flow through the outlet flow line 604 to a fluid transport line (not shown). Additionally, the valve 605 may be a hydraulically remote valve (HCR) to open and close the valve hydraulically and remotely. Furthermore, a check valve 612 or a one way valve, to prevent reverse flow of the fluid, may be used in conjunction with the valve 605. As seen by FIG. 6, the check valve 612 is positioned near the valve 605 on an opposite end of the outlet flow line 604. Further, it is also envisioned that the check valve 612 may also be placed between outlet flow line 604 and valve 605, or there may be a plurality of check valves 612, such as on both sides of the valve 605. Further, while body 601 is described as being the outer housing for the internal rotating annular preventer 600 components (including components providing functionality for rotating control device 610 and annular preventer 611), it is also appreciated that the body may have multiple components, such as a body and bonnet, etc. that may be attached together to form a complete outer structure. The precise arrangement of such components is not a limitation on the present disclosure. A cross-section is taken along the central axis 101 to show the internal workings of the rotating annular preventer 600, is shown in FIG. 7.
Referring to FIG. 7, according to one or more embodiments, the rotating control device 610 has a double seal configuration 703. The double seal configuration 703 has as a first rotating control device (RCD) seal 704 and a second rotating control device (RCD) seal 705 placed above the RCD seal 704. For example, the second RCD seal 705 may act as backup to the RCD seal 704. As such the case, when damage occurs to the first RCD seal 704 or the seal integrity of the first RCD seal 704 is compromised, second PCD seal 705 may provide sealing engagement with tubular 101. There is no limit on the number of RCD seals that may be present. RCD seals 704, 705, together with other components of rotating control device 610, may enable managed pressure drilling to occur. Specifically, RCD seals against a moving tubular (rotationally and axially moving) as drilling fluid is pumped into the wellbore, returns to the surface through the annulus, and is diverted from rotating annular preventer through outlet flow line 604. Thus, rotating control device 610 functionality may be used when the annular preventer (performing well control functionality) 611 is open. Specifically, a wellbore pressure (shown in FIG. 5) is used to engage the RCD seal 704 with the tubular 100 extending through a bore of the rotating annular preventer 600, thus making a seal around the tubular 100 while the tubular 100 rotates and moves axially within the well. Wellbore pressure (shown in FIG. 5) may be transmitted through any passageway or the like that can provide fluid communication between the annulus and RCD seal 704. Additionally, the second RCD seal 705 will also use the wellbore pressure to make a seal around the tubular 100 while the tubular 100 rotates. Furthermore, a rotating control device (RCD) bearing assembly 706 is disposed on the RCD seal 704 and the second RCD seal 705 at outer radial surfaces thereof. The RCD bearing assembly 706 allows for the rotation of either the first RCD seal 704 or the second RCD seal 705 within the rotating control device 610. Thus, as a tubular 100 rotates within the rotating annular preventer 610, the first RCD seal 704 or the second RCD seal 705 will rotate based on the sealing engagement with the tubular 100.
Still referring to FIG. 7, according to one or more embodiments, the annular preventer 611 is below rotating control device 610, and both are housed within a single outer body structure includes an annular preventer (AP) seal 707 that is positioned about the central axis 101. Adjacent to a bottom or outer radial surface of AP seal 707 is a piston 708 having a wedge face. Further, FIG. 7 illustrates that AP seal 707 and the piston 708 both have a cross-section suitable for tubular sealing and actuation, such as by a corresponding face of the piston 708. The AP seal 707 is configured to close around tubular 100 when piston 708 moves up, thus sealing off an annulus between tubular 100 and wellbore (not shown). Piston 708 may be hydraulically actuated to engage and disengage the AP seal 707, thereby opening and closing the annular preventer 611. A wellbore pressure (shown in FIG. 5) may be used in conjunction with the hydraulically actuated piston 708 to close the AP seal 707 around the tubular 100, similar to as described above. By hydraulically actuating piston 708, the piston 708 is not dependent on the wellbore pressure (shown in FIG. 5), thus allowing the piston 708 to engage and disengage the AP seal 708 under any wellbore pressure (shown in FIG. 5). Furthermore, the piston 708 can engage the AP seal 707 to seal upon itself (when no tubular is present) to seal off the wellbore. Additionally, an outlet flow line 604 is disposed below AP seal 707, such at a bottom of the annular preventer 611, to allow a flow of wellbore fluid out of the annular preventer 611. Once an AP seal 707 seals around tubular 100 and valve 605 is opened, the outlet flow line 604 will divert wellbore fluid from the annulus (not shown) since the AP seal 707 has closed the annular flowpath around tubular 100. Furthermore, a check valve 612 or a one way valve, to prevent reverse flow of the fluid, may be used in conjunction with the valve 605. As seen by FIG. 7, the check valve 612 is positioned near the valve 605 on an opposite end of the outlet flow line 604. Further, it is also envisioned that the check valve 612 may also be placed between outlet flow line 604 and valve 605, or there may be a plurality of check valves 612, such as on both sides of the valve 605. Further, in the illustrated embodiment, piston 708 is hydraulically actuated; however, the wellbore pressure (shown in FIG. 5) may enhance the sealing of the AP seal 707 with the tubular 100. The hydraulic actuation may be considered an active sealing system, whereas use of wellbore pressure alone is a passive sealing system. As described above, the rotating control device 610 uses wellbore pressure, and is thus a passive sealing system, and the annular preventer 611 is an active sealing system.
Referring now to FIG. 8, another embodiment of the rotating control device 610 of the rotating annular preventer 600 is shown. In this embodiment, the rotating control device 610 has a single seal configuration 803. As such, the single seal configuration 803 only has the rotating control device (RCD) seal 704. With the annular preventer 611 open, a wellbore pressure (shown in FIG. 5) is used to engage the RCD seal 704 with the tubular 100 extending through a bore of the rotating annular preventer 600, thus, making a seal around the tubular 100 while the tubular 100 rotates. Wellbore pressure (not shown) may be transmitted through any passageway or the like that can provide fluid communication between the annulus and RCD seal 704. Furthermore, a rotating control device (RCD) bearing assembly 706 is disposed on the RCD seal 704 at an outer radial surface thereof. The RCD bearing assembly 706 allows for the rotation of the RCD seal 704 within the rotating control device 610. Thus, as a tubular 100 rotates within the rotating annular preventer 610, the RCD seal 704 will rotate based on the sealing engagement with the tubular 100.
Thus, there are a number of variations that may be made on the rotating annular preventer of the present disclosure. The single device may integrate the conventionally two separate devices/functionalities by just sharing the bonnet/body for the RCD and annular preventer, or the device may integrate internal components. Further, as also described above, the various sealing elements (also referred to in the art as a packing assembly) can be operated as an active sealing system, passive sealing system, or with combinations thereof. While the rotating annular preventer integrates two functions of well control and managed pressure drilling, it is understood that the dynamic pressure rating of the device (considered while moving tubulars) may be less than static rating (considered when no tubulars are present) due to movement of tubulars (either axially or rotationally).
Further, as described, embodiments of the present disclosure may include one or more hydraulic lines, such as for the hydraulically actuated piston, for cooling of a bearing assembly, etc. In one or more embodiments, hydraulic lines for opening and closing the annular preventer (such as by moving the piston) can be distinct from the lubricant oil lines. Further, it is also envisioned that hydraulic lines for operating the RAP in well control situations can be separate from hydraulic lines for operating the RAP during managed pressure drilling and underbalanced drilling operations. Sealing elements can be divided into separate compartments for MPD/UBD operation or well control operation. When the RAP is not needed, it will be fully opened by applying hydraulic pressure to position/reposition its piston axially downward, allowing the retraction/repel of the sealing elements (packing assembly). When RAP is needed, the piston will move upward to the closed position and cause the sealing elements (packing assembly) to squeeze inward towards any object or itself in order to seal off completely the annulus or even open wellbore. These and other actuations and tasks can be mechanized and automated to fulfill all the required tasks from health monitoring and preventive maintenance as well as operation and well construction. Specifically, the entire process can be mechanized/automated and a software used to control the operation.
It is also envisioned that the sealing pressure of the one or more sealing elements can be adjusted and regulated (either automatically or manually), particularly for passing different shape of tubulars (for example, due to collars, stabilizers, tool joints, etc.) under a variety of wellbore pressures. In an active or combination system, when different geometry of tubulars are passing through the sealed elements under different wellbore conditions, the pressure of hydraulic oil system can be adjusted and regulated automatically or manually to ensure the optimum proper sealing of the annulus.
While the invention has been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of the invention as disclosed herein. Accordingly, the scope of the invention should be limited only by the attached claims.
Patent Application
20190024473
