Abstract:
The present disclosure provides a casing seal for a wellhead, including a casing with an internal surface having an annular groove therein. A fluid seal is disposed in the annular groove and includes an internal bead for sealing against a cylindrical surface of an inner case or tube. A swellable material is disposed within the annular groove and surrounds the fluid seal. An energizing port is in communication with the annular groove for delivering fluid to the swellable material to cause the swellable material to expand and further load the fluid seal.

Description:
FIELD 
     The present disclosure relates to annular wellhead seals and more particularly, to a wellhead seal having a fluid seal with swellable material packing. 
     BACKGROUND 
     This section provides background information related to the present disclosure which is not necessarily prior art. 
     Once a natural gas or oil well is drilled, the well must be completed to allow for the flow of petroleum or natural gas out of the formation and up to the surface. This process includes strengthening the well hole with a casing structure and then installing equipment to ensure efficient flow of natural gas or oil out of the well. The well casing consists of a series of metal tubes installed in the freshly drilled hole. The casings strengthen the sides of the well hole, ensures that no oil or natural gas seeps out of the well hole as it is brought to the surface, and keeps other fluids or gases from seeping into the formation through the well. Often times, there are multiple different layers of casings, including a conductor casing which is typically installed first prior to drilling with the drilling rig. The conductor casing is installed to prevent the top of the well from caving in and to help in the process of circulating the drilling fluid up from the bottom of the well. This casing is sometimes between 16-20 inches in diameter and is cemented into place before filling begins. A surface casing is the next type of casing to be installed. It can be anywhere from a few hundred to two-thousand feet long and is smaller in diameter than the conductor casing. When installed, the surface casing fits inside the top of the conductor casing. The primary purpose of the surface casing is to protect fresh water deposits near the surface of the well from being contaminated by leaking hydrocarbons or salt water from deeper underground. It also serves as a conduit for drilling mud returning to the surface and helps protect the drill hole from being damaged during drilling. The surface casing, like the conductor casing, is cemented into place. 
     An intermediate casing is usually the longest section of casing found in a well. The primary purpose of the intermediate casing is to minimize the hazards that come along with subsurface formations that may affect the well. These include abnormal underground pressure zones, underground shale, and formations that might otherwise contaminate the well, such as underground salt water deposits. In many instances, even though there may be no evidence of an unusual underground formation, the intermediate casing is run as insurance against the possibility of such a formation affecting the well. Liner strings are sometimes used instead of the intermediate casing. Liner strings are commonly run from the bottom of another type of casing to the open well area. 
     A production casing, alternatively called the oil string or long string, is installed last and is the deepest section of casing in a well. This is the casing that provides a conduit from the surface of the well to the petroleum-producing formation. The size of the production casing depends on a number of considerations, including the lifting equipment to be used, the number of completions required, and the possibility of deepening the well at a later time. 
     The wellhead consists of the pieces of equipment mounted at the opening of the well to manage the extraction of hydrocarbons from the underground formation. It prevents leaking of oil and natural gas out of the well, and also prevents blowouts caused by high pressure. Formations that are under high pressure typically require wellheads that can withstand a great deal of upward pressure of the escaping gases and liquids. These wellheads must be able to withstand pressures of up to 20,000 pounds per square inch. The wellhead typically consists of three components, the casing head, the tubing head, and the christmas tree. 
     The casing head consists of heavy fittings that provide a seal between the fitting and the surface of the casings. The casing head also serves to support the entire length of casing that is run all the way down the well. This piece of equipment typically contains a gripping mechanism that ensures a tight seal between the head and the casing itself. The tubing head is much like the casing head; it provides a seal between the tubing, which is run inside the casing, and the surface. Like the casing head, the tubing head is designed to support the entire length of the casing, as well as provide connections at the surface which allow the flow of fluids out of the well to be controlled. The christmas tree is the piece of equipment that fits on top of the casing and tubing heads, and contains tubes and valves that control the flow of hydrocarbons and other fluids out of the well. It commonly contains many branches and is shaped somewhat like a tree, thus its name “christmas tree.” The christmas tree is the most visible part of a producing well, and allows for the surface monitoring and regulation of the production of hydrocarbons from a producing well. As previously noted, the components of the casing head provide a tight seal between the casing and the surface of the inner casings. 
     SUMMARY 
     This section provides a general summary of the disclosure, and is not a comprehensive disclosure of its full scope or all of its features. 
     The present disclosure provides a casing seal for a wellhead, including a casing with an internal surface having an annular groove therein. A fluid seal is disposed in the annular groove and includes an internal bead for sealing against a cylindrical surface of an inner case or tube. A swellable material is disposed within the annular groove and surrounds the fluid seal. An energizing port is in communication with the annular groove for delivering fluid to the swellable material to cause the swellable material to expand and further load the fluid seal. 
     Further areas of applicability will become apparent from the description provided herein. The description and specific examples in this summary are intended for purposes of illustration only and are not intended to limit the scope of the present disclosure. 
    
    
     
       DRAWINGS 
       The drawings described herein are for illustrative purposes only of selected embodiments and not all possible implementations, and are not intended to limit the scope of the present disclosure. 
         FIG. 1  is a partial cross-sectional view of a wellhead incorporating a fluid seal with swellable material packing, according to the principles of the present disclosure; 
         FIG. 2  is a cross-sectional view of a casing seal according to the principles of the present disclosure; and 
         FIG. 3  is a cross-sectional view taken along a different cross section of the casing seal according to the principles of the present disclosure. 
     
    
    
     Corresponding reference numerals indicate corresponding parts throughout the several views of the drawings. 
     DETAILED DESCRIPTION 
     Example embodiments will now be described more fully with reference to the accompanying drawings. 
     Example embodiments are provided so that this disclosure will be thorough, and will fully convey the scope to those who are skilled in the art. Numerous specific details are set forth such as examples of specific components, devices, and methods, to provide a thorough understanding of embodiments of the present disclosure. It will be apparent to those skilled in the art that specific details need not be employed, that example embodiments may be embodied in many different forms and that neither should be construed to limit the scope of the disclosure. In some example embodiments, well-known processes, well-known device structures, and well-known technologies are not described in detail. 
     The terminology used herein is for the purpose of describing particular example embodiments only and is not intended to be limiting. As used herein, the singular forms “a,” “an,” and “the” may be intended to include the plural forms as well, unless the context clearly indicates otherwise. The terms “comprises,” “comprising,” “including,” and “having,” are inclusive and therefore specify the presence of stated features, integers, steps, operations, elements, and/or components, but do not preclude the presence or addition of one or more other features, integers, steps, operations, elements, components, and/or groups thereof. The method steps, processes, and operations described herein are not to be construed as necessarily requiring their performance in the particular order discussed or illustrated, unless specifically identified as an order of performance. It is also to be understood that additional or alternative steps may be employed. 
     When an element or layer is referred to as being “on,” “engaged to,” “connected to,” or “coupled to” another element or layer, it may be directly on, engaged, connected or coupled to the other element or layer, or intervening elements or layers may be present. In contrast, when an element is referred to as being “directly on,” “directly engaged to,” “directly connected to,” or “directly coupled to” another element or layer, there may be no intervening elements or layers present. Other words used to describe the relationship between elements should be interpreted in a like fashion (e.g., “between” versus “directly between,” “adjacent” versus “directly adjacent,” etc.). As used herein, the term “and/or” includes any and all combinations of one or more of the associated listed items. 
     Although the terms first, second, third, etc. may be used herein to describe various elements, components, regions, layers and/or sections, these elements, components, regions, layers and/or sections should not be limited by these terms. These terms may be only used to distinguish one element, component, region, layer or section from another region, layer or section. Terms such as “first,” “second,” and other numerical terms when used herein do not imply a sequence or order unless clearly indicated by the context. Thus, a first element, component, region, layer or section discussed below could be termed a second element, component, region, layer or section without departing from the teachings of the example embodiments. 
     Spatially relative terms, such as “inner,” “outer,” “beneath,” “below,” “lower,” “above,” “upper,” and the like, may be used herein for ease of description to describe one element or feature&#39;s relationship to another element(s) or feature(s) as illustrated in the figures. Spatially relative terms may be intended to encompass different orientations of the device in use or operation in addition to the orientation depicted in the figures. For example, if the device in the figures is turned over, elements described as “below” or “beneath” other elements or features would then be oriented “above” the other elements or features. Thus, the example term “below” can encompass both an orientation of above and below. The device may be otherwise oriented (rotated 90 degrees or at other orientations) and the spatially relative descriptors used herein interpreted accordingly. 
     With reference to  FIG. 1 , a partial cross-sectional view of a wellhead  10  according to the principles of the present disclosure will now be described. The wellhead  10  receives a production tubing  12  that is surrounded by an intermediate casing  14 , a surface casing  16 , and a conductor casing  18  as discussed previously in the background section of the present application. Without intending to be limited by example, the production tubing  12  can be 4.5 inches in diameter, while the intermediate casing  14  can be 9⅝ inches in diameter, the surface casing  16  can be 13⅜ inches in diameter, and the conductor casing  18  can be 20 inches in diameter. The wellhead  10  can include casing segments  20  that surround and sealingly engage the casings  14 ,  16 , and  18 . The casing segment  20  can be part of a welded assembly  21 , as shown in  FIG. 1 , or can have other configurations. 
     With reference to  FIGS. 2 and 3 , the annular casing  20  has an inner surface  22  and can include one or more recessed grooves  24  therein. An energizing port  26  is provided for each groove  24  and extends from an outer surface of the casing  20  to the recessed groove  24 . Each energizing port  26  can be provided with a threaded bore  28  for receiving a threaded connection. The threaded connection can be connected to a check valve  30  and pump  32  that allow the introduction of a fluid to the energizing port  26 . 
     A fluid seal  40  is disposed in the annular recessed grooves  24 . The fluid seals have an inner surface  42  for sealingly engaging a cylindrical surface of a casing member ( 14 ,  16 ,  18 ) and an outer surface  44 . The fluid seals  40  are surrounded by a swellable material  50  that is disposed in the recessed groove and extends around the outer surface  44  of the fluid seal  40 . The swellable material  50  can be an oil swellable material or other type of known swellable material which, when exposed to a fluid such as oil, causes the material  50  to swell and apply external pressure on the fluid seal  40  to increase the sealing pressure against the outer cylindrical surface of a casing received therein. The fluid seal  40  can include a raised bead portion  45  for engaging the inner casing, as well as recesses  46  on opposite sides of the raised bead  45 . The recesses  46  receive steel springs  60  therein that strengthen the fluid seal  40  and prevent extrusion thereof. 
     As illustrated in  FIG. 3 , the annular recessed groove  24  can include a secondary groove channel  62  extending radially therefrom for providing a channel for delivery of the fluid from the energizing port  26  around the entire periphery of the groove  24  in order to adequately wet and thereby swell the swellable material  50  around the entire perimeter thereof. It is noted that the outer surface  44  of the fluid seal  40  can include a recessed groove therein for receiving the swellable material  50 . The energizing port  26  can be utilized to re-energize the swellable material  50  by introducing oil at various intervals in order to re-energize the seal  40 . The use of the pump  32  and check valve  30  allows the oil or other fluid introduced through the energizing port to be controlled and maintained within the energizing port. A test port  70  can be provided for communicating with the space between the fluid seals  40  in order to test the seals  40  for adequate sealing pressure. 
     The annular casing  20  can include a radially extending flange  20   a  having a plurality of bolt holes  80  therethrough to allow the annular casing  20  to be mounted to adjacent casing members  20 . The casing member  20  can include an annular recessed groove  82  in a face thereof that can receive an axial end portion  84  of an adjacent (typically larger) casing member  20 . 
     It is noted that the fluid seals can be made of an elastomer or other known sealing material, while the casing  20  can be made of steel or other known materials. The swellable material can include several different types of commercially available elastomers that will swell sufficiently in the created fluid environment. Examples include acrylonitrile butadiene rubber (NBR), hydrogenated nitrile butadiene rubber (HNBR), and fluoroelastomer (FKM). 
     With the seal design of the present disclosure, the proposed design utilizes a swellable medium to preload and permanently energize the seal in both primary and secondary applications. The use of the swellable material provides a simplification of the wellhead, as well as improved reliability. 
     The foregoing description of the embodiments has been provided for purposes of illustration and description. It is not intended to be exhaustive or to limit the disclosure. Individual elements or features of a particular embodiment are generally not limited to that particular embodiment, but, where applicable, are interchangeable and can be used in a selected embodiment, even if not specifically shown or described. The same may also be varied in many ways. Such variations are not to be regarded as a departure from the disclosure, and all such modifications are intended to be included within the scope of the disclosure.