Patent Application
20120043726
1Field of the Invention
The present disclosure generally relates to apparatus and methods for sealing in offshore wellbores. More particularly, the present disclosure relates to apparatus and methods to seal against a drill pipe in subsea wellbores offshore during drilling operations.
2. Background Art
Wellbores are drilled deep into the earth's crust to recover oil and gas deposits trapped in the formations below. Typically, these wellbores are drilled by an apparatus that rotates a drill bit at the end of a long string of threaded pipes known as a drillstring. Because of the energy and friction involved in drilling a wellbore in the earth's formation, drilling fluids, commonly referred to as drilling mud, are used to lubricate and cool the drill bit as it cuts the rock formations below. Furthermore, in addition to cooling and lubricating the drill bit, drilling mud also performs the secondary and tertiary functions of removing the drill cuttings from the bottom of the wellbore and applying a hydrostatic column of pressure to the drilled wellbore.
As wellbores are drilled several thousand feet below the surface, the hydrostatic column of drilling mud serves to help prevent blowout of the wellbore as well. Often, hydrocarbons and other fluids trapped in subterranean formations exist under significant pressures. Absent any flow control schemes, fluids from such ruptured formations may blow out of the wellbore like a geyser and spew hydrocarbons and other undesirable fluids (e.g., H2S gas) into the atmosphere. As such, several thousand feet of hydraulic “head” from the column of drilling mud helps prevent the wellbore from blowing out under normal conditions.
However, under certain circumstances, the drill bit will encounter pockets of pressurized formations and will cause the wellbore to “kick” or experience a rapid increase in pressure. Because formation kicks are unpredictable and would otherwise result in disaster, flow control devices known as blowout preventers (“BOPs”), are mandatory on most wells drilled today. One type of BOP is an annular blowout preventer. Annular BOPs are configured to seal the annular space between the drillstring and the inside of the wellbore. Annular BOPs typically include a large flexible rubber packing unit of a substantially toroidal shape that is configured to seal around a variety of drillstring sizes when activated by a piston. Furthermore, when no drillstring is present, annular BOPs may even be capable of sealing an open bore. While annular BOPs are configured to allow a drillstring to be removed (i.e., tripped out) or inserted (i.e., tripped in) therethrough while actuated, they are not configured to be actuated during drilling operations (i.e., while the drillstring is rotating). Because of their configuration, rotating the drillstring through an activated annular blowout preventer would rapidly wear out the packing element.
As such, rotating control devices are frequently used in oilfield drilling operations where elevated annular pressures are present. A typical rotating control device (RCD) includes a packing element and a bearing package, whereby the bearing package allows the packing element to rotate along with the drillstring. Therefore, in using a RCD, there is no relative rotational movement between the packing element and the drillstring, only the bearing package exhibits relative rotational movement. Examples of RCDs include U.S. Pat. No. 5,022,472 issued to Bailey et al. on Jun. 11, 1991 (assigned to Drilex Systems), and U.S. Pat. No. 6,354,385 issued to Ford et al. on Mar. 12, 2002, assigned to the assignee of the present application, and both are hereby incorporated by reference herein in their entirety. In some instances, dual stripper rotating control devices having two sealing elements, one of which is a primary seal and the other a backup seal, may be used. As the assembly of the bearing package along with the sealing elements and the drillstring rotate, leaks may occur between the drillstring and the primary sealing element. An apparatus or method of detecting and isolating leaks between the drillstring and sealing element while drilling would be well received in the industry.
In one aspect, the embodiments disclosed herein relate to a modular seal unit for a rotating control device for use in an offshore environment, the modular seal unit including a first outer housing, a first seal housing lockable within the first outer housing, and a first sealing element disposed on a lower end of the first seal housing, the first sealing element including a throughbore configured to receive a drill pipe and a sealing surface configured to seal against the drill pipe. The modular seal unit also includes a first connector configured to couple the first seal housing to the first outer housing and a second connector configured to couple the first seal housing to one selected from a group including a second outer housing of a second modular seal unit and a running tool adapter.
In another aspect, embodiments disclosed herein relate to a seal assembly for a rotating control device including at least two modular seal units, wherein a top of a first modular seal unit is configured to connect to a bottom of a second modular seal unit. Each modular seal unit includes a first outer housing, a first seal housing lockable within the first outer housing, and a first sealing element disposed on a lower end of the first seal housing, the first sealing element including a throughbore configured to receive a drill pipe and a sealing surface configured to seal against the drill pipe. The modular seal unit further includes a first connector configured to couple the first seal housing to the first outer housing, and a second connector configured to couple the first seal housing to one selected from a group including a second outer housing of a second modular seal unit and a running tool adapter.
In yet another aspect, embodiments disclosed herein relate to a method of assembling a seal assembly, the method including providing a lower outer housing, installing the lower outer housing downhole, locking a first seal housing and a first sealing element within the lower outer housing, connecting a first modular seal unit to the first seal housing, and connecting the second modular seal unit to the first modular seal unit. The first modular seal unit includes a second outer housing, a second seal housing lockable within the second outer housing, a second sealing element disposed on a lower end of the second seal housing, a first connector configured to couple the second seal housing to the second outer housing, and a second connector configured to couple the second seal housing to one selected from a group including a second modular seal unit and a running tool adapter. The second sealing element includes a throughbore configured to receive a drill pipe, and a sealing surface configured to seal against the drill pipe.
Other aspects and advantages of the invention will be apparent from the following description and the appended claims.
In one aspect, embodiments disclosed herein relate to a modular seal unit, a seal assembly, and a method for assembling the seal assembly for use in a rotating control device in an offshore environment. More specifically, embodiments disclosed herein relate to a modular seal unit, a seal assembly, and a method for assembling the seal assembly that provide for additional sealing elements to be installed as needed in the offshore rotating control device.
Referring to
From top to bottom, riser assembly 106 includes a diverter assembly 108 (shown including a standpipe and a bell nipple), a slip joint 110, a rotating control device 112, an annular blowout preventer 114, a riser hanger and swivel assembly 116, and a string of riser pipe 118 extending to subsea wellhead (not shown). While one configuration of riser assembly 106 is shown and described in
Because offshore drilling platform 100 is a semi-submersible platform, it is expected to have significant relative axial movement (i.e., heave) between its structure (e.g., rig floor 102 and/or lower bay 104) and the sea floor. Therefore, a heave compensation mechanism must be employed so that tension may be maintained in riser assembly 106 without breaking or overstressing sections of riser pipe 118. As such, slip joint 110 having a lower section 122, an upper section 124, and a seal housing 126, may be constructed to allow 30′, 40′, or more stroke (i.e., relative displacement) to compensate for wave action experienced by drilling platform 100. Furthermore, a hydraulic member 120 is shown connected between rig floor 102 and hanger and swivel assembly 116 to provide upward tensile force to string of riser pipe 118 as well as to limit a maximum stroke of slip joint 110. To counteract translational movement (in addition to heave) of drilling platform 100, an arrangement of mooring lines (not shown) may be used to retain drilling platform 100 in a substantially constant longitudinal and latitudinal area.
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Lower sealing element 408 may be coupled to a lower seal housing 406 using any known coupling means such as, for example, mechanical fasteners, adhesives, and welding. Alternatively, in certain embodiments, lower sealing element 408 may be molded onto lower seal housing 406. Lower seal housing 406 may be connected to lower outer housing 402 using any connecting means known in the art. In select embodiments, lower seal housing 406 may be coupled to lower outer housing 402 using a quick connect coupler such as, for example, a pin and latch connection or a fit and twist connection. Looking to lower outer housing 402, a locking profile 410 may be disposed on an outer surface thereof. Locking profile 410 may be configured to engage a corresponding profile (not shown) disposed on an inner surface of a separate downhole component. In certain embodiments, locking profile 410 disposed on lower outer housing 402 may be designed to engage a corresponding profile disposed on an inner surface of a bearing package 204 (shown in
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Sealing element 416 may be sized having an outer diameter 417 substantially equal to a top inner diameter 420 of lower outer housing 402. Additionally, a lower portion 434 and an upper portion 436 of second seal housing 404 may have an outer diameter substantially equal to top inner diameter 420 of lower outer housing 402, as shown. Between lower portion 434 and upper portion 436, second seal housing 404 may include a shoulder 438. Shoulder 438 may contact a top end of lower outer housing 402 acting as a stop to prevent second seal housing 404 from sliding axially downward with respect to lower outer housing 402.
Second seal housing 404 may further include an inner diameter 430 which may be larger than small inner diameter portion 424 of second sealing element 416 such that when drillstring 442 is disposed through lower portion 400 of seal assembly 300, a chamber 440 may be formed between an outer surface 441 of drillstring 442 and inner surface 431 of second seal housing 404. In certain embodiments, second seal housing 404 may include a port 428 extending between an outermost surface 444 of second seal housing 404 and an inner surface 431 of second seal housing 404 and may be configured to provide a flow of fluid to and from chamber 440. Port 428 may be equipped with a pressure sensor (not shown) for determining a pressure within chamber 440. Those having ordinary skill in the art will appreciate that the pressure sensor (not shown) may further include equipment for storing or transmitting collected data.
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First and second modular seal units 500a, 500b may be connected to each other prior to installation in a rotating control device as shown, or alternatively, may be installed in the rotating control device one at a time. Second modular seal unit 500b is shown connected to first modular seal unit 500a using a mechanical fastener 604 to couple outer housing 606 of second modular seal unit 500b to seal housing 608 of first modular seal unit 500a. As discussed above, any coupling means may be used to connect first and second modular seal units 500a, 500b including, for example, quick connectors such as pin and latch connectors and fit and twist connectors.
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In certain embodiments, pressure between each pair of seals may be distributed either evenly or unevenly. For example, if wellbore pressure is approximately 1000 psi and 6 seals are installed, the pressure between the two bottom seals may be approximately 800 psi, pressure between the next two sets of seals may be approximately 600 psi, and pressure between the top two sets of seals may be approximately 400 psi. In certain embodiments, varying the amount of pressure between certain sets of seals may balance the seals and may increase the life of the seals.
Advantageously, embodiments disclosed herein provide for a seal assembly that may be configured to include as many sealing elements as desired. For example, in certain embodiments, between 3 and 20 modular seal units may be assembled to make up a single seal assembly. In certain embodiments, the seal assembly may initially be equipped with two modular seal units and may be modified over time to include more than 20 modular seal units, as desired. Each modular seal unit included in the seal assembly may also be designed to resist bending such that a seal assembly having multiple modular seal units is supported against bending. Embodiments disclosed herein may allow for longer periods of sustained drilling without changing sealing elements. Additionally, rotational torque may be transferred through an increased sealing surface area and may providing a reduction in slippage of the drillstring with respect to the sealing elements and may also extend sealing element life. Each modular seal unit may be customized by using different sealing element materials, thereby allowing for different sealing element properties such as, for example, wear properties, chemical compatibility, pressure retention, etc. A pin and slot connector may allow for each component of the seal assembly to be installed or retrieved using a standard running tool.
Additionally, because each modular seal unit may include pressure measurement equipment, pressure data may be collected from multiple points within the seal assembly. The ability to collect pressure data from multiple points may advantageously provide for determining effectiveness of each modular seal unit and for detecting fluid leaks at various points within the seal assembly. Moreover, a hydraulic line may provide increased control over fluid pressure at multiple points within the seal assembly.
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.
