Wells – Processes – Placing or shifting well part
Reexamination Certificate
2001-09-10
2004-02-10
Bagnell, David (Department: 3672)
Wells
Processes
Placing or shifting well part
C166S207000, C166S384000
Reexamination Certificate
active
06688399
ABSTRACT:
BACKGROUND OF THE INVENTION
1. Field of the Invention
The present invention relates to wellbore completion. More particularly, the invention relates to an apparatus and method for creating an attachment and a seal between two tubulars in a wellbore.
2. Description of the Related Art
In the drilling of oil and gas wells, a wellbore is formed using a drill bit that is urged downwardly at a lower end of a drill string. After drilling a predetermined depth, the drill string and bit are removed, and the wellbore is lined with a string of steel pipe called casing. The casing provides support to the wellbore and facilitates the isolation of certain areas of the wellbore adjacent hydrocarbon bearing formations. The casing typically extends down the wellbore from the surface of the well to a designated depth. An annular area is thus defined between the outside of the casing and the earth formation. This annular area is filled with cement to permanently set the casing in the wellbore and to facilitate the isolation of production zones and fluids at different depths within the wellbore.
It is common to employ more than one string of casing in a wellbore. In this respect, a first string of casing is set in the wellbore when the well is drilled to a first designated depth. The well is then drilled to a second designated depth, and a second string of casing, or liner, is run into the well to a depth whereby the upper portion of the second liner is overlapping the lower portion of the first string of casing. The second liner string is then fixed or hung in the wellbore, usually by some mechanical slip mechanism well-known in the art, and cemented. This process is typically repeated with additional casing strings until the well has been drilled to total depth.
After the initial string of casing is set, the wellbore is drilled to a new depth. An additional string of casing, or liner, is then run into the well to a depth whereby the upper portion of the liner, is overlapping the lower portion of the surface casing. The liner string is then fixed or hung in the wellbore, usually by some mechanical slip mechanism well known in the art, commonly referred to as a hanger.
Downhole tools with sealing elements are placed within the wellbore to isolate areas of the wellbore fluid or to manage production fluid flow from the well. These tools, such as plugs or packers, for example, are usually constructed of cast iron, aluminum or other alloyed metals and include slip and sealing means. The slip means fixes the tool in the wellbore and typically includes slip members and cores to wedgingly attach the tool to the casing well. In addition to slip means, conventional packers include a synthetic sealing element located between upper and lower metallic retaining rings.
The sealing element is set when the rings move towards each other and compress the element there between, causing it to expand outwards into an annular area to be sealed and against an adjacent tubular or wellbore. Packers are typically used to seal an annular area formed between two coaxially disposed tubulars within a wellbore. For example, packers may seal an annulus formed between production tubing disposed within wellbore casing. Alternatively, packers may seal an annulus between the outside of the tubular and an unlined borehole. Routine uses of packers include the protection of casing from pressure, both well and stimulation pressures, as well as the protection of the wellbore casing from corrosive fluids. Other common uses include the isolation of formations or leaks within a wellbore casing or multiple production zones, thereby preventing the migration of fluid between zones. Packers may also be used to hold fluids or treating fluids within the casing annulus in the case of formation treatment, for example.
One problem associated with conventional sealing and slip systems of conventional down hole tools relates to the relative movement of the parts necessary in order to set the tools in a wellbore. Because the slip and sealing means require parts of the tool to be moved in opposing directions, a run-in tool or other mechanical device must necessarily run into the wellbore with the tool to create the movement. Additionally, the slip means takes up valuable annular space in the wellbore. Also, the body of a packer necessarily requires wellbore space and reduces the bore diameter available for production tubing, etc.
A recent trend in well completion has been the advent of expandable tubular technology. It has been discovered that both slotted and solid tubulars can be expanded in situ so as to enlarge the inner diameter. This, in turn, enlarges the path through which both fluid and downhole tools may travel. Also, expansion technology enables a smaller tubular to be run into a larger tubular, and then expanded so that a portion of the smaller tubular is in contact with the larger tubular therearound. Tubulars are expanded by the use of a cone-shaped mandrel or by an expander tool with expandable, fluid actuated members disposed on a body and run into the wellbore on a tubular string. During expansion of a tubular, the tubular walls are expanded past their elastic limit. Examples of expandable tubulars include slotted screen, joints, packers, and liners. The use of expandable tubulars as hangers and packers allows for the use of larger diameter production tubing, because the conventional slip mechanism and sealing mechanism are eliminated.
While expanding tubulars in a wellbore offers obvious advantages, there are problems associated with using the technology to create a hanger or packer through the expansion of one tubular into another. By plastically deforming the tubular, the cross-sectional thickness of the tubular is necessarily reduced. Simply increasing the initial cross-sectional thickness of the tubular to compensate for the reduced tensile strength after expansion results in an increase in the amount of force needed to expand the tubular.
More importantly, when compared to a conventional hanger, an expanded tubular with no gripping structure on the outer surface has a reduced capacity to support the weight of a liner. This is due to a reduced coefficient of friction of the outer surface of an expandable tubular in comparison to the slip mechanism having teeth or other gripping surfaces formed thereon.
A need therefore exists for an expandable tubular connection with increased strength. There is a further need for an expandable tubular connection providing an improved gripping surface between an expanded tubular and an inner wall of a surrounding tubular.
A further need exists for an expandable tubular with an increased capacity to support the weight of a liner.
SUMMARY OF THE INVENTION
The present invention generally relates to an apparatus and method for engaging a first tubular and a second tubular in a wellbore. The present invention provides a tubular body formed on a portion of a first tubular. The tubular body is expanded so that the outer surface of the tubular body is in frictional contact with the inner surface of a surrounding second tubular. In one embodiment, the tubular body is modified by machining grooves into the surface, thereby reducing the amount of radial force required to expand the tubular body on the first tubular into the surrounding tubular.
The tubular body optionally includes hardened inserts, such as carbide buttons, for gripping the surrounding tubular upon contact. The gripping mechanism increases the capacity of the expanded tubular to support its weight and to serve as a hanger. In another aspect, the outer surface of the expandable tubular body optionally includes a pliable material such as an elastomer within grooves formed on the outer surface, and for increasing the sealing capability of the expandable tubular to an outer tubular.
REFERENCES:
patent: 761518 (1904-05-01), Lykken
patent: 1324303 (1919-12-01), Carmicheal
patent: 1545039 (1925-07-01), Deavers
patent: 1561418 (1925-11-01), Duda
patent: 1569729 (1926-01-01), Duda
patent: 1597212 (1926-08-01), Spengler
patent: 1930825 (1933-10-01)
Maguire Patrick G.
Tran Khai
Gay Jennifer H
Moser, Patterson & Sheridan L.L.P.
Weatherford / Lamb, Inc.
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