Displacement annular swivel
A displacement annular swivel is disclosed consisting of a mandrel with a sleeve assembly positioned around the outside diameter of the mandrel. The sleeve assembly consists of at least one radial bushing such that the mandrel can be rotated and reciprocated within the sleeve assembly when the sleeve assembly is fixed in a stationary position. At least one sealing element is present on the sleeve assembly to radially seal against the outside diameter of the mandrel. A method for displacing drilling mud from a completed subsea wellbore is also disclosed consisting of closing a blowout preventer around the aforementioned tool connected to the work string. The tool thereby allows the work string to be rotated and reciprocated when the blowout preventer is closed. Drilling fluid can then be displaced from the wellbore by pumping a fluid such as completion brine through the work string and out the choke and kill lines.
The present invention relates generally to an apparatus and method for allowing a drill string to rotate and reciprocate while drilling mud is being displaced from a wellbore.
Exploration and production of hydrocarbons from subsea reservoirs is an expensive and time-consuming process. The mechanics of drilling in a marine environment differ significantly from land operations. Drilling operations utilize a weighted drilling fluid, such as drilling mud, which is pumped down the drill string and circulated back to the surface through an annulus between the drill string and the borehole wall. The drilling fluid serves many purposes, such as to cool the drill bit as it rotates and cuts into the earth formation, provide a medium for returning the cuttings created by the drill bit to the earth's surface via the annulus, and control pressure in the borehole to help prevent blowouts. During land operations, the drilling fluid and cuttings are returned to the surface via the borehole annulus. Such is not the case in offshore operations.
Offshore operations, including inland water operations, generally require location of a host drilling facility, such as a floating drilling unit, in waters located above the reservoir of interest. The depth of the water may range from several feet to depths of several thousand feet. A drill string must travel from the surface of the drilling facility, down through the surface and seabed equipment, and then into the wellbore of interest prior to initiating cutting/drilling operations. Unlike land operations, there is no annulus between the floor of the seabed and the drilling facility at the surface. Accordingly, a drilling riser comprised of generally cylindrical elements is provided for and extends generally from a wellhead located at the seabed up to the drilling facility located above the surface of the water. The riser operates to protect the drill string during operations and acts as an artificial annulus.
Subsea drilling operations must provide a means for shutting down the well in emergency situations during drilling completion operations. Generally, a series of blowout preventers (BOPs), referred to as a BOP stack, are used to control well flow in such instances. The BOP stack is connected to the wellhead and generally consists of a combination of ram BOPs and annular BOPs. In conventional subsea drilling systems, the BOP stack is located on the seafloor and requires various umbilical and control lines in order to monitor conditions and hydraulically operate the BOP stack.
A ram BOP is a device that can be used to quickly seal the top of the well in the event of a well control event. A ram BOP consists of two halves of a cover for the well that are split down the middle. Large-diameter hydraulic cylinders, normally retracted, force the two halves of the cover together in the middle to seal the wellbore. These covers are constructed of steel for strength and fitted with elastomer components on the sealing surfaces. The halves of the covers, formally called ram blocks, are available in a variety of configurations. In some designs, they are flat at the mating surfaces to enable them to seal over an open wellbore. Other designs have a circular cutout in the middle that corresponds to the diameter of the rig's drill string (e.g. drill pipe) to seal the well when the drill string is in the hole. Still other ram blocks are fitted with a tool steel-cutting surface to enable the ram BOPs to completely shear through drill pipe, hang the drill string off on the ram blocks themselves and seal the wellbore. This last design, referred to a shear ram BOP, is employed only as a last resort to regain pressure control of the wellbore.
An annular BOP is a large valve in which the sealing element resembles a large elastomeric doughnut that is mechanically squeezed inward to seal on either pipe (drill collars, drill pipe, casing, or tubing) or the openhole. The ability to seal on a variety of pipe sizes is one advantage the annular BOP has over a ram-type BOP. Most BOP stacks contain at least one annular BOP at the top of the BOP stack, and one or more ram BOPs below.
The riser pipe is typically installed on top of the BOP stack. Typically, three smaller lines are attached to the outside of the riser and extend up to the surface drilling facility. Two of the lines, the choke and kill lines, run to connections within the BOP stack and provide a greater means for drilling mud to enter and exit the well when the BOPs are closed. The third line is called a boost line and connects above the BOP stack and provides additional hydraulic support and circulating rates when needed.
After drilling is complete, it is necessary to displace the drilling fluid from the wellbore. This is typically accomplished by closing at least one section of the BOP stack to isolate the wellbore from the riser. Drilling fluid is then displaced out of the riser by pumping fluid, such as seawater, through either the choke or kill line through the BOP stack and up the riser to the surface facility. Drilling fluid can then be displaced from the wellbore by pumping fluid, such as completion brine, down the work string, through the drill bit, up the wellbore annulus, and up the choke or kill line to the surface facility.
The problem with this technique is that it is often desirable to be able to rotate and reciprocate the work string while displacing drilling mud from the wellbore in order to improve displacement efficiencies. However, it is cost prohibitive to rotate and reciprocate the work string with the annular BOPs closed around the work string because of the wear on the rubber elements in the annular BOPs. What is needed is a device and method that would allow for rotation and reciprocation of the work string while drilling fluid is being displaced from the wellbore.
SUMMARY OF THE INVENTIONA novel displacement annular swivel tool and a method for using such a tool is provided to solve the aforementioned problems.
A displacement annular swivel is disclosed consisting of a mandrel with a sleeve assembly positioned around the outside diameter of the mandrel. The sleeve assembly consists of at least one radial bushing such that the mandrel can be rotated and reciprocated within the sleeve assembly when the sleeve assembly is fixed in a stationary position. At least one sealing element is present on the sleeve assembly to radially seal against the outside diameter of the mandrel.
A method for displacing drilling fluid from a completed subsea wellbore is also disclosed consisting of closing a blowout preventer around the aforementioned tool connected to the work string. The tool thereby allows the work string to be rotated and reciprocated when the blowout preventer is closed. Drilling fluid can then be displaced from the wellbore by pumping fluid, such as completion brine, through the work string and out the choke and kill lines.
BRIEF DESCRIPTION OF THE DRAWINGSA more complete understanding of the present invention may be obtained with reference to the accompanying drawing:
With reference to
Both the upper sub 12 and the lower sub 14 contain sealing elements 28 at the connections that make up the mandrel 16. The bottom body cap 22 of sleeve 18 also contains at least one, and preferably two (as shown in
Upper sub 12 and lower sub 14 are connected to sections of drill string above and below said subs such that sleeve 18 is aligned with an annular BOP in a BOP stack when the fully assembled string is run to the bottom of the wellbore. When the annular BOP is closed around sleeve 18, a non-rotating, sealing engagement is created between the elastomeric sealing elements of the annular BOP and sleeve 18. Sealing elements 28 and 30 isolates all fluid circulation below the annular BOP, thereby preventing fluids from back-flowing through the tool and contaminating above the tool.
With annular BOP closed about sleeve 18, sleeve 18 will remain stationary relative to the annular BOP. The drill string and specifically mandrel 16 can then be rotated independent of sleeve 18 due to radial bushings 24 and 26. Furthermore, the drill string and specifically mandrel 16 can also be reciprocated (i.e. raised and lowered) independent of sleeve 18 due to radial bushings 24 and 26, with the length of reciprocation being limited to length of exposed mandrel 16 between upper sub 12 and lower sub 14. In a preferred aspect of the present invention, mandrel 16 is approximately 25 to 35 feet long with sleeve 18 being approximately 10 feet long, thereby providing approximately 15 to 25 feet of reciprocation in either direction from the center of the tool. However, additional mandrel sections (typically 25 to 35 feet long) can be added to the tool in order to increase the range of reciprocation.
With the annular BOP closed about sleeve 18, drilling mud in the wellbore is then isolated from fluid in the riser. Drilling mud displacement can then proceed. Drilling mud is displaced out of the riser by pumping fluid, such as seawater, through the choke or kill line, through the BOP stack, and up the riser to the surface facility. Drilling mud is then displaced from the wellbore by pumping fluid, such as completion brine, down the work string, through the drill bit, up the wellbore annulus, and up the choke or kill lines to the surface facility. During this displacement step, the work string can be rotated and reciprocated about sleeve 18, which remains stationary, without any damage to the elastomeric elements of the annular BOP.
As described above, upper sub 12 and lower sub 14 are connected to sections of drill string (or work string more generally) such that sleeve 18 is aligned with an annular BOP in a BOP stack when the fully assembled string is run to the bottom of the wellbore. In a preferred aspect of the present invention, displacement annular swivel tool 10 is approximately 31 to 40 feet long, which can correspond to approximately the length of a typical section of string. Accordingly, the fully assembled string including the tool can be assembled in the same manner as a typical drill string. The displacement annular swivel tool 10 can either be fully assembled prior to connection with the adjoining sections of string, or alternatively it can be assembled in a “top-down” or “bottom-up” manner. Top-down assembly would occur, for example, by first connecting upper sub 12 to the adjoining top string section, then connecting mandrel 16 with sealing element 28. Next, the full sleeve assembly 18, including top body cap 20, bottom body cap 22, top radial bushing 24, bottom radial bushing 26, and sealing elements 30 are slid onto mandrel 16. A stop, such as a casing clamp for example, is used to hold sleeve assembly 18 on mandrel 16 until lower sub 14 with sealing element 28 is connected to the bottom of mandrel 16. Once fully assembled, lower sub 14 is then connected to the adjoining bottom string section. The displacement annular swivel tool may be stood back in the derrick until lowered downhole.
Although the preferred embodiment is described for use with an annular BOP, it is envisioned that one of ordinary skill in the art can design a tool in accordance with the teachings of the present invention to be used in conjunction with a pipe ram-type BOP. In such an alternative embodiment the outside diameter of sleeve 18 must be substantially equivalent to the outside diameter of the drill string for which the ram BOP was designed in order to properly seal the riser from the wellbore.
Similarly, although the preferred embodiment is described for use with a single annular BOP, it is envisioned that one of ordinary skill in the art can design a tool in accordance with the teachings of the present invention to be used in conjunction with more than one BOP. For example, sleeve 18 can be designed with sufficient length so as to be able to receive the elastomeric sealing elements of two or more annular BOPs in a BOP stack. As another example, sleeve 18 can be designed with sufficient length and with the appropriate outside diameter as described above so as to be able to receive the sealing elements for a combination of one or more annular BOPs and one or more ram-type BOPs.
It will be apparent to one of skill in the art that described herein is a novel displacement annular swivel tool and a method for using such a tool to provide for rotation and reciprocation of the work string during drilling mud displacement. While the invention has been described with references to specific preferred and exemplary embodiments, it is not limited to these embodiments. The invention may be modified or varied in many ways and such modifications and variations as would be obvious to one of skill in the art are within the scope and spirit of the invention and are included within the scope of the following claims.
Claims
1. A method for displacing drilling fluids from a wellbore, comprising:
- closing a blowout preventer around a tool connected to a work string; and
- displacing drilling fluid from the wellbore;
- wherein the work string can be rotated and reciprocated during the displacing step.
2. The method of claim 1, wherein the wellbore is a subsea wellbore.
3. The method of claim 1, wherein the blowout preventer is an annular blowout preventer.
4. The method of claim 1, wherein the drilling fluid is displaced by pumping fluid through the work string.
5. The method of claim 4, wherein the fluid is completion brine.
6. The method of claim 1, wherein the drilling fluid is displaced through at least one line connected to the wellbore below the closed blowout preventer.
7. The method of claim 6, wherein the at least one line is selected from the choke line or the kill line.
8. The method of claim 1, wherein the tool comprises:
- a mandrel, the mandrel having a first length and an outside diameter; and
- a sleeve assembly positioned around the outside diameter of the mandrel, the sleeve assembly having a second length that is smaller than the first length.
9. The method of claim 8, wherein the blowout preventer is closed around the sleeve assembly.
10. The method of claim 9, wherein the sleeve assembly is substantially stationary when the blowout preventer is closed.
11. The method of claim 8, wherein the mandrel is rotated within the sleeve assembly when the work string is rotated.
12. The method of claim 8, wherein the mandrel is reciprocated within the sleeve assembly when the work string is reciprocated.
13. The method of claim 8, wherein the sleeve assembly further comprises at least one sealing element that seals radially on the outside diameter of the mandrel.
14. A displacement annular swivel, comprising:
- a mandrel, the mandrel having a first length and an outside diameter; and
- a sleeve assembly positioned around the outside diameter of the mandrel, the sleeve assembly having a second length that is smaller than the first length;
- wherein the mandrel can be rotated within the sleeve assembly when the sleeve assembly is fixed in a stationary position.
15. The tool of claim 14, wherein the sleeve assembly comprises at least one radial bushing.
16. The tool of claim 14, wherein the mandrel can be reciprocated when the sleeve assembly is fixed in a stationary position.
17. The tool of claim 14, wherein the sleeve assembly further comprises at least one sealing element that seals radially on the outside diameter of the mandrel.
18. The tool of claim 17, wherein the at least one sealing element is an o-ring.
19. The tool of claim 14, further comprising an upper sub connected to the top of the mandrel and a lower sub connected to the bottom of the mandrel.
20. The tool of claim 14, wherein the upper sub connects to a string section above the tool and the lower sub connects to a string section below the tool.
Type: Application
Filed: Feb 11, 2005
Publication Date: Aug 17, 2006
Inventors: Neal Bracksieck (Tomball, TX), David Hebert (Scott, LA)
Application Number: 11/057,303
International Classification: E21B 33/035 (20060101); E21B 21/00 (20060101);
