Patent Grant
9175542
N/A.
N/A
N/A
1. Field of the Invention
This invention relates to sealing elements used in drilling wells.
2. Description of Related Art
Sealing elements have been used in rotating control devices (RCDs) for many years in the drilling industry. Passive sealing elements, such as stripper rubber sealing elements, can be fabricated with a desired stretch-fit. An example of a proposed stripper rubber sealing element is shown in U.S. Pat. No. 5,901,964. A stripper rubber sealing element may be attached with a rotatable internal bearing member of an RCD to seal around the outside diameter of an inserted tubular to rotate with the tubular during drilling. The tubular may be slidingly run through the RCD as the tubular rotates or when the tubular, such as a drill string, casing, coil tubing, or any connected oilfield component, is not rotating. Examples of some proposed RCDs are shown in U.S. Pat. Nos. 5,213,158; 5,647,444 and 5,662,181.
RCDs have been proposed with a single stripper rubber seal element, as in U.S. Pat. Nos. 4,500,094 and 6,547,002; and Pub. No. US 2007/0163784, and with dual stripper rubber sealing elements, as in the '158 patent, '444 patent and the '181 patent, and U.S. Pat. No. 7,448,454. The wellbore pressure in the annulus acts on the cone shaped stripper rubber sealing element with vector forces that augment a closing force of the stripper rubber sealing element around the tubular. U.S. Pat. No. 6,230,824 proposes two opposed stripper rubber sealing elements, the lower sealing element positioned axially downward, and the upper sealing element positioned axially upward (see FIGS. 4B and 4C of '824 patent).
Unlike a stripper rubber sealing element, an active sealing element typically requires a remote-to-the-tool source of hydraulic or other energy to open or close the sealing element around the outside diameter of the tubular. An active sealing element can be deactivated to reduce or eliminate the sealing forces of the sealing element with the tubular. RCDs have been proposed with a single active sealing element, as in the '784 publication, and with a stripper rubber sealing element in combination with an active sealing element, as in U.S. Pat. Nos. 6,016,880 and 7,258,171 (both with a lower stripper rubber sealing element and an upper active sealing element), and Pub. No. US 2005/0241833 (with a lower active sealing element and an upper stripper rubber sealing element).
A tubular typically comprises sections with varying outer surface diameters. The RCD sealing element must seal around all of the rough and irregular surfaces of the components of the tubular, such as a hardening surface (as proposed in U.S. Pat. No. 6,375,895), drill pipe, tool joints, drill collars, and other oilfield components. The continuous movement of the tubular through the sealing element while the sealing element is under pressure causes wear of the inwardly facing sealing surface of the sealing element.
When drilling with a RCD having dual independent annular sealing elements, the lower of the two sealing elements is typically exposed to the majority of the pressurized fluid and cuttings returning from the wellbore, which communicate with the lower surface of the lower sealing element body. The upper sealing element is exposed to the fluid that is not blocked by the lower sealing element. When the lower sealing element blocks all of the pressurized fluid, the lower sealing element is exposed to a significant pressure differential across its body since its upper surface is essentially at atmospheric pressure when used on land or atop a riser. The highest demand and wear on the RCD sealing elements occurs when tripping the tubular out of the wellbore under high pressure.
American Petroleum Institute Specification 16RCD (API-16RCD) entitled “Specification for Drill Through Equipment—Rotating Control Devices,” First Edition,® February 2005 American Petroleum Institute, proposes standards for safe and functionally interchangeable RCDs. The requirements for API-16RCD must be complied with when moving the drill string through an RCD in a pressurized wellbore. The sealing element is inherently limited in the number of times it can be fatigued with larger diameter tool joints that pass under high differential pressure conditions. Of course, the deeper the wellbores are drilled, the more tool joints that will be stripped through a sealing element, some under high pressure.
RCDs have been proposed in the past to be positioned with marine risers. An example of a marine riser and some of the associated drilling components is proposed in U.S. Pat. Nos. 4,626,135 and 7,258,171. U.S. Pat. No. 6,913,092 proposes a seal housing with a RCD positioned above sea level on the upper section of a marine riser to facilitate a mechanically controlled pressurized system. U.S. Pat. No. 7,237,623 proposes a method for drilling from a floating structure using an RCD positioned on a marine riser. U.S. Pat. Nos. 6,470,975; 7,159,669; and 7,258,171 propose positioning an RCD assembly in a housing disposed in a marine riser. Also, an RCD has also been proposed in U.S. Pat. No. 6,138,774 to be positioned subsea without a marine riser.
Latching assemblies have been proposed in the past for positioning an RCD. U.S. Pat. No. 7,487,837 proposes a latch assembly for use with a riser for positioning an RCD. Pub. No. US 2006/0144622 proposes a latching system to latch an RCD to a housing. Pub. No. US 2008/0210471 proposes a docking station housing positioned above the surface of the water for latching with an RCD. Pub. No. US 2009/0139724 proposes a latch position indicator system for remotely determining whether a latch assembly is latched or unlatched.
In the past, when drilling in deepwater with a marine riser, the riser has not been pressurized by mechanical devices during normal operations. The only pressure induced by the rig operator and contained by the riser is that generated by the density of the drilling mud held in the riser (hydrostatic pressure). During some operations, gas can unintentionally enter the riser from the wellbore. If this happens, the gas will move up the riser and expand. As the gas expands, it will displace mud, and the riser will “unload.” This unloading process can be quite violent and can pose a significant fire risk when gas reaches the surface of the floating structure via the bell-nipple at the rig floor.
U.S. Pat. No. 4,626,135 proposes a gas handler annular blowout preventer (BOP) to be installed in the riser. The gas handler annular BOP is activated only when needed, but instead of simply providing a safe flow path for mud and gas away from the rig floor, the gas handler annular BOP can be used to hold limited pressure on the riser to control the riser unloading process. However, drilling must cease because movement of the drill string through the annular BOP when the annular seal is engaged against the drill string will damage or destroy the non-rotatable annular seal. During drilling, the annular BOP's seal is open, and drilling mud and cuttings return to the rig through the annulus or annular space. Ram type blowout preventers have also been proposed in the past for drilling operations, such as proposed in U.S. Pat. Nos. 5,735,502; 4,488,703; 4,508,313; and 4,519,577. As with annular BOPs, drilling must cease when the ram BOP seal is engaged against the drill string tubular or damage to the seal will occur.
Prior to the development of RCDs, packing heads, such as proposed in U.S. Pat. Nos. 2,038,140; 2,124,015; 2,148,844; 2,163,813; and 2,287,205, were used for sealing around the drill string during drilling operations. Unlike an RCD, a packing head has no bearing assembly and its sealing element does not rotate with the drill string or other inserted tubular or oilfield component. U.S. Pat. No. 2,170,915 proposes a stationary stripper rubber seal positioned in a housing over a well casing through which the drill string may be rotated for drilling. A problem with such prior art packing head and stationary stripper rubber devices is that the sealing element can be damaged or destroyed by the heat generated from the friction resisting the movement of the inserted tubular or oilfield component.
Drilling with casing is gaining some acceptance worldwide for addressing certain onshore and offshore problems such as formation instability, lost circulation, fluids control, and troublesome zones. Drilling with casing eliminates the need to continually replace strings of drill pipe during drilling, saving time since the rig is also drilling while casing is being run into the hole. Although drilling with casing currently constitutes only a small part of worldwide drilling activity, drilling with casing is expected to increase in the future.
Drilling with casing is being attempted with increasingly larger casing sizes. While drilling with casing has been used in the past with 9⅝ inch (24.4 cm) diameter casing, it is now being attempted with casing diameters up to 20 inches (50.8 cm). However, the amount of annular space within a riser or housing for positioning an RCD becomes increasing more limited as the casing size gets larger. The RCD has to be sized to accommodate the large casing, and it is often impractical to use a larger riser or housing, particularly in shallow wells or other applications where the larger casing is only needed for relatively short drilling distances, like 100 feet (30.5 m). Drilling with casing may be attempted in the future in certain subsea applications without a marine riser, particularly for drilling relatively short drilling distances.
Testing performed by the inventors reveals that when a 10¾ inch (27.3 cm) diameter casing section is rotated in a prior art stationary stripper rubber sealing element under low pressures of 5 to 10 psi, the prior art sealing element deteriorates and is damaged in about 2 to 10 hours due to heat generated by the frictional resistive forces. When water is applied to the prior art sealing element surfaces not contacting the casing section, the sealing element damage does not occur until about 30 hours. However, when drilling with casing is used in real drilling applications, much longer drilling times are needed.
Circular seal members positioned within grooves, chambers, pockets or receptacles have been used in the past in applications involving rotating shafts. Kalsi Engineering, Inc. of Houston, Tex. and Parker Hannifin, Inc. of Cleveland, Ohio are two manufacturers of such sealing members. U.S. Pat. No. 4,610,319 proposes a circular sealing member for a drill bit application having a wave pattern on the sealing side of the sealing member and positioned within a circular pocket. The sealing member receives lubrication in the pocket from an external lubricant supply system source. U.S. Pat. Nos. 5,230,520; 5,678,829; 5,738,358; 5,873,576; 6,007,105; 6,036,192; 6,109,618; 6,120,036; 6,227,547; 6,315,302; 6,334,619; 6,382,634; 6,494,462; 6,561,520; and 6,685,194 propose circular seals having sealing interfaces with various geometries and disposed within receptacles, grooves, chambers, or pockets. The seal receptacle, groove, chamber or pocket supports and stabilizes the circular seal and may be used to receive lubricant for the seal from an external lubricant supply source.
International Pub. No. WO2008/133523 proposes a packer seal element with at least one channel within the seal for moving a lubricant through the seal. The packer element is positioned around the drill string, and the lubricant, proposed to be oil or grease, is injected from an external source into a port in the side of the packer seal for travel through the channel in the seal. U.S. Pat. No. 3,472,518 proposes a stationary metal housing positioned close to the surface of a drill pipe with the housing inner surface having a series of rings or grooves forming a tortuous path between the outer surface of the drill pipe and the inner surface of the housing. The tortuous path is proposed to provide for a fluid flow that absorbs the pressure drop from the pressure in the annulus around the drill pipe below the housing to atmospheric pressure on the exterior of the housing.
The above discussed U.S. Pat. Nos. 2,038,140; 2,124,015; 2,148,844; 2,163,813; 2,170,915; 2,287,205; 3,472,518; 4,488,703; 4,500,094; 4,508,313; 4,519,577; 4,610,319; 4,626,135; 5,213,158; 5,230,520; 5,647,444; 5,662,181; 5,678,829; 5,735,502; 5,738,358; 5,873,576; 5,901,964; 6,007,105; 6,016,880; 6,036,192; 6,109,618; 6,120,036; 6,138,774; 6,227,547; 6,230,824; 6,315,302; 6,334,619; 6,375,895; 6,382,634; 6,470,975; 6,494,462; 6,547,002; 6,561,520; 6,685,194; 6,913,092; 7,159,669; 7,237,623; 7,258,171; 7,448,454; and 7,487,837; and Pub. Nos. US 2005/0241833; 2006/0144622; 2007/0163784; 2008/0210471; and 2009/0139724; and International Pub. No. WO2008/133523 are all hereby incorporated by reference for all purposes in their entirety.
It would be desirable to drill with a sealed and pressurized mud system without using an RCD. Particularly, it would be desirable to drill using casing with a sealed and pressurized mud system without using an RCD. It would be desirable to drill for relatively short distances using larger casing sizes without an RCD since the annular space surrounding such casing may be limited. It would be desirable to drill with a non-rotating BOP device that would allow drilling to continue with the sealing element sealed without the sealing element becoming damaged or destroyed from the heat and other effects of friction in a relatively short time period. It would also be desirable to drill with a non-rotating BOP device in relatively shallow subsea wells without a marine riser. It would be desirable to use sealing elements in an RCD that would not become damaged or destroyed from the heat and other effects of friction in a relatively short time period when the RCD bearings or other RCD components malfunction in providing sufficient seal element rotation. It would also be desirable to have a sealing element with bi-directional or redundant sealing. It would be desirable to decrease the differential pressure across the lower seal element in a dual seal configuration.
A system and method are provided for drilling using a sealing element having a lubricating seal profile on the inwardly facing bore surface of its sealing section. The lubricating seal profile allows for sealing a drill string tubular or other oilfield component and communicating a fluid between the sealing section of the sealing element and the sealed drill string tubular or other oilfield component while the drill string tubular or other oilfield component rotates and/or slides vertically relative to the sealing element. The sealing element may seal with the drill string tubular or other oilfield component and either remain stationary and non-rotating, or it may rotate. The same fluid used for drilling may also be used for lubrication, such as water, drilling fluid, mud, well bore fluid or other gas or liquid.
In one embodiment, the sealing element may be positioned with a seal housing above or with a marine riser. In another embodiment, the seal element may be positioned with a seal housing in a marine riser. In yet another embodiment, the sealing element may be positioned with a seal housing subsea without a marine riser. A seal adapter housing may keep the sealing element stationary and non-rotating while the sealed drill string tubular or other oilfield component rotates relative to the sealing element. In another embodiment, the seal housing may be a RCD that allows the sealing element to rotate with the sealed drill string tubular or other oilfield component.
The lubricating seal profile allows for communicating a fluid between the sealing section of the sealing element and the sealed drill string tubular or other oilfield component when the RCD sealing element either slows or stops rotating and the sealed drill string tubular or other oilfield component continues to rotate relative to the sealing element, such as when the RCD bearings malfunction or require bearing lubrication. In still other embodiments, the sealing element having a lubricating seal profile may be positioned with a BOP, such as an annular BOP or a ram-type BOP, allowing the sealed drill string tubular or other oilfield component to continue rotating relative to the BOP sealing element.
More than one sealing element having a lubricating seal profile may be positioned with a seal housing. In one embodiment, sealing elements may be positioned axially downwardly. In another embodiment, sealing elements may be opposed both axially downwardly and axially upwardly. A dual sealing element or dual seal may have two annular sealing surfaces that are spaced apart by a non-sealing surface. In one embodiment, a dual seal may be a unitary bi-directional sealing element having lubricating seal profiles on the inwardly facing surfaces of each of its two nose sections. In another embodiment, a dual seal may have a lubricating seal profile on the inwardly facing surface of its nose section and a lubricating seal profile on the backup or bi-directional sealing surface adjacent the throat section. The dual seal embodiments also may not have any lubricating seal profiles on their spaced apart annular sealing surfaces. In another embodiment, differential pressures across two seal elements may be managed by filling the cavity between the two seal elements with cuttings-free drilling fluid, mud, water, coolant, lubricant or inert gas at desired amounts of pressure.
All embodiments of the dual seal may have a hydraulic force surface to move, deform or compress one or both of the sealing surfaces with a drill string tubular or other oilfield component. The hydraulic force surface may take many different forms of embodiments, including a closed curved or radius surface, an open inclined surface, an open curved surface, a combination open inclined surface with a horizontal or flat surface, a combination open curved surface with horizontal or flat surface, and a combination closed upper and lower curved surfaces with a sealing surface therebetween.
The lubricating seal profile may have many different embodiments, including, but not limited to, a wave pattern or wavy edge, a saw-tooth high film pattern, a downwardly inclined passageway pattern, an upwardly inclined passageway pattern, and a combination upwardly and downwardly inclined passageway pattern. The lubricating seal profile may be positioned and oriented on the inwardly facing sealing surface of the sealing element based upon the intended direction of flow of the lubricating fluid. A lubricating seal profile may be positioned and oriented on either or both of the spaced apart sealing surfaces of a dual seal based upon the intended direction of flow of the lubricating fluid.
In one embodiment, a stripper rubber sealing element may have an annular lubricating seal profile on the inwardly facing bore surfaces of both its nose section and its throat section. The nose section may seal with a drill string tubular or other oilfield component having a first diameter, and the throat section and nose section may deform to seal with an oilfield component of the drill string tubular having a second and larger diameter, such as a tool joint.
The system and method allow drilling without an RCD using larger casing sizes with a sealing element sealed with the casing. The system and method also allow drilling with a non-rotating BOP device, such as an annular BOP or a ram-type BOP, that allow drilling to continue with the sealing element engaged and without the sealing element becoming damaged or destroyed from the heat and other effects of friction in a relatively short time period. The system and method also allow drilling with casing using a non-rotating BOP device in relatively shallow subsea wells without a riser. The system and method further allow the use of sealing elements with an RCD that will not become damaged or destroyed from the heat and other effects of friction in a relatively short time period when the RCD bearings or other RCD components malfunction and do not allow adequate or desired rotation. The system and method further allow for dual seals with sealing surfaces for redundant, back up or bi-directional sealing with or without lubricating profiles and for use with or without a rotating tubular or other oilfield component.
A better understanding of the embodiments may be obtained with the following detailed descriptions of the various disclosed embodiments in the drawings, which are given by way of illustration only, and thus are not limiting the invention, and wherein:
In
Second seal or second sealing element 18 is disposed with seal housing 8 with its second seal supporting or throat section 24. Second sealing element 18 has a second seal lubricating seal profile 20 on the inwardly facing sealing surface 21 of it nose section or sealing section 22 for sealing with drill string tubular DS. Although two seal elements (10, 18) are shown, any number of sealing elements are contemplated, including only one sealing element. Seal housing 8 is an adapter or seal adapter housing that keeps sealing elements (10, 18) stationary and does not allow the sealing elements (10, 18) to rotate as drill string tubular DS rotates or moves vertically, such as during drilling.
First and second seal lubricating profiles (12, 20) may be the same or they may be different. First and second seal lubricating profiles (12, 20) shown in
The location and orientation of profiles (12, 20) in
When the pressurized fluid flows up the annular space 26 in
Passive sealing elements, such as first sealing element 10 and second sealing element 18 in
For each of the sealing elements (10, 18), each of their respective seal support or throat sections (16, 24) and sealing or nose sections (14, 22) may have a different wear resistance. Their sealing sections (14, 22) and profiles (12, 20) may also each have a different wear resistance. Since the sealing sections are not compressed against a groove, each of the sealing sections (14, 22) has a stretch fit or other urging member(s) to seal the profiles (12, 20) with the drill string tubular DS or other inserted oilfield component. It is contemplated that first sealing element 10 and second sealing element 18, as well as all sealing elements in any other embodiment shown in any of the Figures, may be made in whole or in part from SULFRON® material, which is available from Teijin Aramid BV of the Netherlands. SULFRON® materials are a modified aramid derived from TWARON® material. SULFRON material limits degradation of rubber properties at high temperatures, and enhances wear resistance with enough lubricity, particularly to the nose, to reduce frictional heat. SULFRON material also is stated to reduce hysteresis, heat build-up and abrasion, while improving flexibility, tear and fatigue properties. It is contemplated that the stripper rubber sealing element may have para aramid fibers and dust. It is contemplated that longer fibers may be used in the throat of the stripper rubber sealing element to add tensile strength, and that SULFRON material may be used in whole or in part in the nose of the stripper rubber sealing element to add lubricity.
The '964 patent proposes a stripper rubber with fibers of TWARON® material of 1 to 3 millimeters in length and about 2% by weight to provide wear enhancement in the nose. It is contemplated that the stripper rubber may include 5% by weight of TWARON to provide stabilization of elongation, increase tensile strength properties and resist deformation at elevated temperatures. Para amid filaments may be in a pre-form, with orientation in the throat for tensile strength, and orientation in the nose for wear resistance. TWARON and SULFRON are both registered trademarks of Teijin Aramid BV of the Netherlands.
It is further contemplated that material properties may be selected to enhance the grip of the sealing element. A softer elastomer of increased modulus of elasticity may be used, typically of a lower durometer value. An elastomer with an additive may be used, such as aluminum oxide or pre-vulcanized particulate dispersed in the nose during manufacture. An elastomer with a tackifier additive may be used. This enhanced grip of the sealing element would be beneficial when one of multiple sealing elements is dedicated for rotating with the tubular.
It is also contemplated that the sealing elements of all embodiments may be made from an elastomeric material made from polyurethane, HNBR (Nitrile), Butyl, or natural materials. Hydrogenated nitrile butadiene rubber (HNBR) provides physical strength and retention of properties after long-term exposure to heat, oil and chemicals. It is contemplated that polyurethane and HNBR (Nitrile) may preferably be used in oil-based drilling fluid environments 160° F. (71° C.) and 250° F. (121° C.), and Butyl may preferably be used in geothermal environments to 250° F. (121° C.). Natural materials may preferably be used in water-based drilling fluid environments to 225° F. (107° C.).
It is contemplated that one of the stripper rubber sealing elements may be designed such that its primary purpose is not for sealability, but for assuring that the inner member of the RCD rotates with the tubular, such as a drill string. This sealing element may have rollers, convexes, or replacement inserts that are highly wear resistant and that press tightly against the tubular, transferring rotational torque to the inner member. It is contemplated that all sealing elements for all embodiments in all the Figures may comply with the API-16RCD specification requirements.
It is contemplated that the pressure between sealing elements (10, 18) may be controllable. The concept of controlling pressure between sealing elements as disclosed in this application is proposed in U.S. Pat. No. 8,347,983. U.S. Pat. No. 8,347,983 is owned by the assignee of the present invention and is hereby incorporated by reference for all purposes in its entirety. The cavity between the sealing elements (10, 18) may be pressurized with cuttings-free drilling fluid, water, mud, coolant, lubricant or inert gas for the purpose of decreasing the differential pressure across the lower sealing element 10 and/or flushing its sealing surface 13 for the purpose of reducing wear and extending seal element life. The cuttings-free fluid may be supplied at a pressure higher than the pressure below the lower sealing element 10, such as 120 psi higher, so as to allow the cuttings free fluid to lubricate between the drill string DS and the sealing surface 13. Similarly, it is contemplated that the pressure between all sealing elements shown for all embodiments in all of the Figures may be controllable. All cavities between the sealing elements for all embodiments shown in all of the Figures may be pressurized with cuttings-free drilling fluid, mud, water, coolant, lubricant or inert gas for the purpose of decreasing the differential pressure across the lower sealing element and/or flushing its sealing surface for the purpose of reducing wear. The cavity fluid may also include lubricant from the bearings, coolant from a cooling system, or hydraulic fluid used to active an active sealing element.
Sensors can be positioned to detect the wellbore annulus fluid pressure and temperature and the cavity fluid pressure and temperature and at other desired locations. The pressures and temperatures may be compared, and the cavity fluid pressure and temperature applied in the cavity may be adjusted. The pressure differential to which one or more of the sealing elements is exposed may be reduced. The cavity fluid may be circulated, which may be beneficial for lubricating and cooling or may be bullheaded. The stationary seal adapter housing and/or RCD may have more than two sealing elements. Pressurized cavity fluids may be communicated to each of the internal cavities located between the sealing elements. Sensors can be positioned to detect the wellbore annulus fluid pressure and temperature and the cavity fluid pressures and temperatures. Again, the pressures and temperatures may be compared, and the cavity fluid pressures and temperatures in all of the internal cavities may be adjusted.
Turning to
Continuing with
First seal lubricating profile 46 and second seal first and second lubricating profiles (58, 64) may be the same or they may be different. The application of the lubricating seal profiles (46, 58, 64) shown in
Under normal operations of seal housing or RCD 49, sealing elements (42, 52) rotate with the sealed drill string tubular DS. Therefore, fluid would not communicate between the seal elements (42, 52) and the drill string tubular DS because of lack of relative rotation between the seal elements (42, 52) and the tubular DS. However, any of the profiles on the seal elements disclosed herein may be configured such that fluid may communicate between the seal elements and tubular DS from any vertical movement of tubular DS relative to the seal elements. If the RCD 49 does not allow adequate rotation of the sealing elements (42, 52), such as when the RCD bearings 45 become damaged or require lubrication, there may be relative rotational movement between the sealed drill string tubular DS and the sealing elements (42, 52). In such situations, when the pressurized fluid bypasses or flows up the annular space 68 in
The fluid may then bypasses upwards through annulus 68A, encountering second seal first profile passageway 60. Again, as the drill string tubular DS moves and/or rotates relative to the sealing elements (42, 52), the pressurized fluid communicates between second seal first sealing surface 57 and drill string tubular DS, lubricating second seal 52. The same fluid communication between the sealing elements (42, 52) and the drill string tubular DS occurs when seal housing 40 is not an RCD and does not allow rotation of the seal elements (42, 52) with the tubular DS. Also, like an RCD, vertical movement provides limited lubrication. The fluid may be the same fluid used for drilling, such as water, drilling fluid or mud, well bore fluid or other gas or liquids.
Second seal second profile 64 is positioned and orientated for intended fluid flow downward from the annular space 70 between drill string tubular DS and marine riser upper tubular section 38. In such situations, when the fluid moves down the annular space 70 while drill string tubular DS is rotating and/or moving vertically relative to second seal 52, the fluid first encounters second seal second profile passageway 66. As the drill string tubular DS moves and/or rotates relative to the seal elements (42, 52), the pressurized fluid in annulus 70 communicates between second seal second sealing surface 63 and drill string tubular DS, lubricating second seal 52. It is contemplated that second seal second profile 64 may be alternatively positioned for intended fluid flow from below, like first seal profile 46 and second seal first profile 58. For such alternative lubricating profile position, the second seal second profile would be similar to that shown in
Each of the sealing elements (42, 52) respective seal support or throat sections (44, 54A, 54B) and sealing or nose sections (48, 56A, 56B) may have different wear resistances. Their sealing sections (48, 56A, 56B) and profiles (46, 58, 64) may each have different wear resistances. Each of the sealing elements (42, 52) sealing sections (48, 56A, 56B) may provide a stretch fit to seal the profiles (46, 58, 64) with the drill string tubular DS or other oilfield component. The lubricating seal profiles may be used in different orientations and/or locations with any of the sealing elements (42, 52) in
In
Second seal or second sealing element 94 is disposed with seal housing 80 with its second seal supporting or throat section 96. Second seal 94 has a second seal lubricating seal profile 100 on the inwardly facing sealing surface 101 of its nose section or sealing section 98, which is sealed with drill string tubular DS. Although two sealing elements (82, 94) are shown, any number of sealing elements are contemplated, including only one sealing element. Seal housing 80 is an adapter or seal adapter housing that keeps sealing elements (82, 94) stationary so as not to allow rotation as drill string tubular DS rotates and moves vertically, such as during drilling. However, it is also contemplated that seal housing 80 may be an RCD, such as seal housing 49 shown on the left side of the break line BL in
First seal lubricating profile 88 and second seal lubricating profile 100 may be the same or they may be different. The lubricating seal profiles (88, 100) shown in
First seal profile 88 is positioned and oriented with the intention of fluid flowing up the annular space 92 between the drill string tubular DS and the lower tubular section 72 or the diverter housing 74. Like in
When the pressurized fluid flows up the annular space 92 in
It is contemplated that second seal profile 100 may be alternatively positioned for intended fluid flow from below, like first seal profile 88. For such alternative lubricating profile position, the second seal profile would be similar to that shown in
If seal housing 80 is an RCD, during normal operations the sealing elements (82, 94) rotate with the sealed drill string tubular DS. Therefore, fluid would not communicate between the seal elements (82, 94) and the drill string tubular DS because of lack of relative rotation between the seal elements (82, 94) and the tubular DS; however, to a lesser degree, fluid would communicate between the seal elements (82, 94) and tubular DS from any vertical movement of tubular DS relative to the vertically fixed seal elements (82, 94). If the RCD slows or stops rotating, such as from bearing failure or lack of bearing lubrication or some other problem, the drill string tubular DS may rotate relative to the sealing elements (82, 94). In such a situation, the sealing elements (82, 94) may allow lubrication from the fluid as described above for a stationary seal housing 80, thereby advantageously minimizing or reducing damage to the seal elements (82, 94).
For each sealing element (82, 94), their respective seal support or throat sections (84, 96) and sealing or nose sections (86, 98) may have different wear resistances. Their sealing sections (86, 98) and profiles (88, 100) may have different wear resistances. The respective sealing sections (86, 98) of the sealing elements (82, 94) may provide a stretch fit to seal the profiles (88, 100) with the drill string tubular DS or other oilfield component.
Turning to
In
As best shown in
Seal support or throat section 120 and sealing or nose section 116 may have a different wear resistance. Sealing section 116 and profile 118 may have a different wear resistance. Sealing section 116 may provide a stretch fit to seal the profile 118 with the drill string tubular DS or other oilfield component.
Turning to
As best shown in
The saw-tooth pattern profile 132 provides for high fluid leakage for increased film thickness. Seal support or throat section 136 and sealing or nose section 130 may have a different wear resistance. Sealing section 130 and profile 132 may have a different wear resistance. Sealing section 130 may provide a stretch fit to seal the profile 132 with the drill string tubular DS or other oilfield component.
Turning to
Turning to
Turning to
Downwardly inclined passageways 172 are also formed in the sealing surface 168 of the sealing section 170. The downwardly inclined passageways 172 are positioned in the inwardly facing surface 168 of nose section 170 for intended fluid flow downwardly in the passageways 172 surrounding an inserted drill string tubular DS (not shown). As the drill string tubular DS moves vertically and/or rotates relative to seal element 166, such as during drilling, the fluid may move through downward inclined passageways 172 and communicate fluid between sealing surface 168 and drill string tubular DS, thereby lubricating seal element 166. As can now be understood, the lubricating seal profile shown in
For each of the sealing elements (142, 158, 166) shown in
Turning to
Downwardly inclined passageways 188 are also formed in the first sealing surface 182 of the first sealing section 184. The downwardly inclined passageways 188 are positioned in the inwardly facing first sealing surface 182 of nose section 184 for intended fluid flow downwardly in the passageways 188 surrounding drill string tubular DS (shown in
Sealing element 180 also has a downwardly inclined passageway pattern lubricating seal profile or second profile formed in the inclined inwardly facing second sealing surface 192 that spans both nose section 184 and throat section 194 to create a second sealing section. Downwardly inclined passageways 190 are formed in the second sealing surface 192 for intended fluid flow downwardly in the passageways 190 surrounding drill string tubular DS with a larger diameter component, such as tool joint TJ best shown in
As shown in
As can now be understood, stripper rubber 180 has a first annular sealing surface 182 having a first sealing diameter and a first profile, and a second annular sealing surface 192 having a second sealing diameter greater than the first sealing diameter and a second profile. Drill string tubular DS having a first tubular diameter may be in contact with the first profile 182 (
First seal or first sealing element 196 is disposed with seal housing (200, 211) with its first seal supporting or throat section 204. During manufacture, an attachment member or metal ring having a plurality of threaded openings is inserted in the supporting or throat section 204 to receive threaded studs or bolts having threaded studs circumferentially spaced about the circumference of the seal element 196 or stripper rubber for mounting of the seal element 196 or stripper rubber with the mounting ring (as shown) of the rotating control device (RCD) seal housing (200, 211). First sealing element 196 has a seal lubricating seal profile 202 on the inwardly facing sealing surface 201 of its first seal nose section or sealing section 206, which is sealed with drill string tubular DS. Seal lubricating seal profile 202 is a wave pattern best shown in
Second seal or second sealing element 198 is a dual seal best shown in
As can now be understood, second sealing element 198 is a dual seal with two annular sealing sections (220, 212) and sealing surfaces (207, 209) that are spaced apart by a nonsealing surface 208. It is contemplated that second sealing element 198 may be a single unit. It may be formed or molded as a unitary or monolithic unit. Although two sealing elements (196, 198) are shown in
First seal lubricating profile 202 is consistent with either a wave pattern or wavy edge lubricating seal profile, such as shown in
The orientation and location of the first seal lubricating seal profile 202 is for fluid flow down the annular space 224 between the drill string tubular DS and the marine riser upper tubular section 38. Like in
Under normal operations of seal housing or RCD 211, sealing elements (196, 198) may rotate with the sealed drill string tubular DS. Therefore, fluid would not communicate between the seal elements (196, 198) and the drill string tubular DS because of lack of relative rotation between the seal elements (196, 198) and the tubular DS. However, as discussed above, a profile on one and/or the other of the seal elements (196, 198) may be configured such that fluid may communicate between the seal elements (196, 198) and tubular DS from any vertical movement of tubular DS relative to the seal elements (196, 198). If the RCD does not allow adequate rotation of the sealing elements (196, 198), such as when the RCD bearings become damaged or require bearing lubrication, there may be relative movement between the sealed drill string tubular DS and the sealing elements (196, 198). In such situations, when the pressurized fluid flows down the annular space 224 while drill string tubular DS is rotating or moving vertically, and dual seal 198 has lubricating seal profiles (not shown) on its sealing surfaces (207, 209), the fluid may communicates between the second seal second sealing surfaces (207, 209) and chill string tubular DS, lubricating dual seal 198.
The fluid may then move downwards, encountering first seal profile passageways 214. As the drill string tubular DS moves and/or rotates relative to the first sealing element 196, the pressurized fluid communicates fluid between first seal first sealing surface 201 and drill string tubular DS, lubricating first sealing element 196.
The same fluid communication between the sealing elements (196, 198) and the drill string tubular DS occurs when dual seal 198 has lubricating seal profiles (not shown) and seal stationary adapter housing 200 does not allow rotation of the sealing elements (196, 198). The fluid may be the same fluid used for drilling, such as water, drilling fluid or mud, well bore fluid or gas or other liquids. Although the first seal lubricating seal profile 202 is intended for downward fluid flow, it is also contemplated that that any of the lubricating seal profiles disclosed may be selected for upward fluid flow.
Seal second profile is a downwardly inclined passageway pattern, with downwardly inclining passageways 244 formed in the inwardly facing second sealing surface 230 of throat or support section 234. An annular closed curved or radius hydraulic force surface 238 is formed in the top of the throat section 234. The annular hydraulic force surface 238 allows fluid flowing downward to apply a force and either move, deform or compress second sealing surface 230 against the sealed drill string tubular DS (not shown). The hydraulic force surface 238 also allows fluid flowing downward to move, deform or compress seal 226 downward, adding to the sealing force of second sealing surface 230 against the sealed drill string tubular DS. It is contemplated that the hydraulic force surfaces may be a continuing annular surface, although spaced apart or equidistant segmented hydraulic force surfaces could also be used for any of the embodiments disclosed herein. The fluid to apply a force may be the fluid used for drilling, such as water, drilling fluid or mud, well bore fluid or gas or other liquids.
For the sealing elements (180, 196, 198, 226) in
Turning to
In
An annular open inclined or angled hydraulic force surface 262 is formed in the top of the throat section 258. The annular hydraulic force surface 262 allows fluid flowing downward to apply a force to either move, deform or compress second sealing surface 260 against the sealed drill string tubular DS (not shown). The annular hydraulic force surface 262 also allows fluid flowing downward to move, deform or compress seal 250 downward, adding to the sealing capacity of second sealing surface 260 against the sealed drill string tubular DS. It is contemplated that spaced apart or segmented hydraulic forces surfaces may be used with any of the dual seals shown in any of the
In
Turning to
In
In
The foregoing disclosure and description of the invention are illustrative and explanatory thereof, and various changes in the details of the illustrated apparatus and system, and the construction and the method of operation may be made without departing from the spirit of the invention.
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| Number | Date | Country | |
|---|---|---|---|
| 20110315404 A1 | Dec 2011 | US |
