Abstract:
The present invention provides for a valve in a tubing string that allows the tubing string to fill with well fluids as the string is assembled and lowered into a well bore, but can be used to check pressure integrity of the tubing string during various stages of the assembly.

Description:
This application claims the benefit of U.S. Provisional Application 60/373,540 filed Apr. 16, 2002. 

   BACKGROUND 
   1. Field of Invention 
   The present invention pertains to valves used in subsurface well completions, and particularly to valves in tubing strings that allow well fluids to freely enter the tubing string from below the valve, but can isolate the tubing string below the valve from pressure applied to the fluid in the tubing above the valve. 
   2. Related Art 
   Tubing used in a subsurface well, such as production tubing, is generally assembled at the well site using sectional lengths or “joints”. A first joint is lowered into the well bore until its upper end is at the well bore (or platform) surface. Each successive joint after the first is then joined to the joint just below it, conventionally using “box and pin” threaded connectors, and the assembled section of tubing string is lowered into the well bore by the length of the added joint. The process is repeated until a tubing string of desired length is assembled. 
   It is generally desirable to allow well bore fluids to enter the tubing as it is lowered into the well bore. This is easily achieved by having an open bottom on the first joint, or otherwise providing fluid communication between the well bore and the tubing interior, such as by providing ports. However, it is important to insure the assembled tubing string can hold pressure. To insure pressure integrity, an operator needs to occasionally test such integrity, as various joints are added, by applying pressure to the fluid in the tubing interior. However, the fluid communication path between the well bore and the tubing interior prevents such pressure from building unless the communication path is selectively blocked. 
   One attempted solution uses a first nipple that is placed above a packer as part of the tubing string. A first plug can be run on slick line, wireline, coiled tubing, or pipe and set inside the first nipple to block communication between the well bore and the tubing interior. That allows pressure-testing the tubing to full pressure without setting the hydraulic set packer. With that configuration, the packer setting intake pressure port is not exposed to the tubing pressure that occurs above the plug. After pressure-testing, the first plug is removed and the tubing string is further assembled. 
   That method requires an intervention to set and remove the plug each time an operator wishes to pressure-test the tubing string. In addition, to set the hydraulic set packer, a second nipple must be included in the tubing string below the packer. A second plug is run and set inside the second nipple below the packer, and pressure is applied in the tubing to set the packer. The plug is then removed. This requires further intervention which translates to expensive rig time, especially in an offshore environment. Also, each intervention increases the risk of getting stuck in the hole, and could create a hazardous situation. 
   In an alternative solution, a nipple and plug is run below the packer, and a tubing fill valve is run above the nipple/plug, but below the packer. The tubing is filled through the packer filling valve. The packer filling valve is closed, preferably using some intervention-less method such as pumping fluid from tubing to annulus at a certain rate to create a pressure differential from tubing to casing that can be used to close the tubing fill valve. Pressure can then be applied in the tubing to pressure test tubing integrity. The hydraulic packer setting port is exposed to the tubing pressure since the plug (in this case) is run below the packer. Hence, the tubing can not be tested to the desired full pressure without setting the packer. Packer setting pressure is normally lower then the desired tubing test pressure. Therefore, the tubing can be tested only to the lower packer setting pressure, and that is undesirable in most cases. 
   After the (lower) pressure test, the tubing fill valve must be reopened by some means to allow the tubing to fill as the tubing is assembled and lowered into the hole. This takes more rig time and there is a possibility of swabbing the packer&#39;s sealing element due to fluid flowing past the packer element at a high rate while the tubing fill valve is not reopened. 
   Thus, a need exists to selectively isolate the fluid communication between the tubing interior and the well bore whenever desired while running in the hole, while still allowing the well bore fluids free entry into the tubing interior when pressure integrity is not being tested. There also exists a need to allow pressure-testing of the tubing to a desired pressure that is generally higher then the packer setting pressure, without setting the packer during the pressure test. 
   SUMMARY 
   The present invention provides for a valve in a tubing string that allows the tubing string to fill with well fluids as the string is assembled and lowered into a well bore, but can be used to check pressure integrity of the tubing string during various stages of the assembly. 
   Advantages and other features of the invention will become apparent from the following description, drawings, and claims. 

   
     DESCRIPTION OF FIGURES 
       FIG. 1  is a partial cross section and schematic view of a tubing fill and testing valve constructed in accordance with the present invention. 
       FIGS. 2–7  are enlarged sectional views of the invention of  FIG. 1 . 
   

   DETAILED DESCRIPTION 
   Referring to all the figures, but particularly to  FIG. 1 , a tubing fill and testing valve  10  comprises a power module  12  and a valve module  14 . Power module  12  and valve module  14  are mounted in a housing  16 . Housing  16  may be a single piece or may comprise multiple members joined in a conventional manner such as threaded connections. 
   Power module  12  comprises a moveable power sleeve  18  having a piston head  20  that travels within a sealed chamber  22 . Chamber  22  is defined above and below by seals  24  and  26 , respectively, and is divided into an upper chamber  28  and a lower chamber  30  by a seal  32  carried by piston head  20 . Upper chamber  28  is in fluid communication with a control line  34  (although a fluid communication path between the upper chamber  28  and the control line  34  is not shown in the cross-sections of the valve  10  shown in the figures). Lower chamber  30  is in fluid communication with an annular region  36  between housing  16  and a well bore or casing  38  via a port  40 . Seals  24 ,  26 , and  32  all seal against an inner surface of housing  16 . The inner surface of housing  16  is recessed slightly in the region where piston head  20  travels to accommodate piston head  20 . Power sleeve  18  has a smooth profile along most of its inner surface. The smooth inner profile defines an interior passageway  41  through an upper portion of tubing fill and testing valve  10 . A deviation from that smooth inner profile is a selective profile  43  located on the inner surface of power sleeve  18 . 
   Valve module  14  comprises a moveable valve sleeve  42 , a flapper  44 , and a tubing  46 . Valve sleeve  42  has an upper end  48  having a shoulder  50  adapted to receive and engage a lower end  52  of power sleeve  18 . Lower end  52  has a liner sleeve  53  that extends passageway  41  some length below shoulder  50 . When lower end  52  is received and engaged by upper end  48 , valve sleeve  42  and power sleeve  18  move in unison. Valve sleeve  42  has a tapered or contoured lower end  54  such that valve sleeve  42  is longer on one side than on the opposite side. An annular recess  56  exists between tubing  46  and housing  16 . Recess  56  receives lower end  54  of valve sleeve  42  when valve sleeve  42  moves to its lower position within housing  16 . 
   Tubing  46  has a seat  58  located on an upper end  60  of tubing  46 . Flapper  44  is pivotally attached by hinge  62  to upper end  60  of tubing  46 . Flapper  44  may be biased by a spring (not shown) to a closed position. When flapper  44  is in its closed state, flapper  44  seals against seat  58 . Flapper  44  has a protruding tang  64  extending past hinge  62  above recess  56 . Tubing  46  also has a port  66  to allow fluid communication between an interior passageway  67  of tubing  46  and recess  56 . An isolation sleeve  68  is moveably mounted on tubing  46  within recess  56 . Isolation sleeve  68  carries seals  70 ,  72  to block port  66  when isolation sleeve  68  is positioned such that seals  70  and  72  seal on an outer surface of tubing  46  above and below port  66 . Isolation sleeve  68  may be held in place over port  66  by shear pins  74 . 
   In operation, tubing fill and testing valve  10  is run into well bore  38  on completion string. Tubing fill and testing valve  10  can be placed and held in its open state or it can be preferably placed in its closed state since well fluids would not be prevented from entering interior passageways  41  and  67  from beneath flapper  44 . Even if the flapper is biased closed, the bias would not be so strong as to offer substantial resistance to entry of fluids from below. At any desired depth, a pressure integrity test can be performed by applying fluid pressure within passageway  41  above closed flapper  44 . The pressure drives flapper  44  toward its sealed configuration. Such pressure tests can be run at various depths as the length of the completion string increases. 
   Upon reaching a desired depth, and after completing all pressure tests, pressurized fluid can be applied through control line  34  to place and hold flapper  44  in its open state. The pressurized fluid bears on piston head  20  through upper chamber  28 . The pressurized fluid drives power sleeve  18  downward, which forces valve sleeve  42  downward as well. As valve sleeve  42  moves downward, its longer side encounters isolation sleeve  68 . Continued downward motion shears off shear pins  74  and pushes isolation sleeve  68  downward into recess  56  to expose port  66 , allowing fluid communication between the passageways  41  and  67 . This allows pressure differences across flapper  44  to equalize. 
   Continued downward motion causes the shorter side of valve sleeve  42  to encounter and bear on tang  64 . This forces flapper  44  to pivot open. Still further downward motion causes liner sleeve  53  to pass alongside the (now raised) lower surface of flapper  44  and engage upper end  60  of tubing  46 . Thus, passageways  41  and  67  are then joined. Flapper  44  is trapped in the open position between the outer surface of liner sleeve  53  and an inner surface of valve sleeve  42 . Flapper  44  is out of the flow path. Thus, there is no danger of hanging an intervention tool on flapper  44  as it is now isolated. 
   Selective profile  43  is provided to allow a shifting tool to be latched onto power sleeve  18  should fluid pressure not suffice, fluid communication through control line  34  be blocked or severed, or there is otherwise some failure of the fluid to move power sleeve  18 . The shifting tool can be run, for example, on coiled tubing, wireline, slick line, or drill pipe to push or pull power sleeve  18  down or up to open or close valve  10 . In the existing arts, to open a flapper valve, a flapper actuator, commonly called a flow tube, impinges on the flapper such that the flapper rotates away from the actuator. The actuator pushes on the sealing side of the flapper, swings the flapper open, and passes beside the flapper to cover it and form an unobstructed flow path. In conventional fill tube valves using a flapper valve, it is not possible to open the flapper using a mechanical shifting tool because the flapper actuator is below the closed flapper valve. To mechanically access the flapper actuator, the flapper must first be opened. The present invention allows the flapper actuator to be placed on the upper (non-sealing) side of the flapper. Thus, a shifting tool can be run in and latched to the actuator even if the flapper is in the closed position. 
   The present invention also increases the diameter through the flapper valve compared to prior art valves. In prior art valves, because the flapper actuator is situated below the flapper and must pass through the upper end of the tubing, it must have an outer diameter that is smaller than the inner diameter of the tubing. The present invention uses an actuator, liner sleeve  53 , situated above the flapper and having an inner diameter equal to the inner diameter of tubing  46 . This allows a larger inner diameter through the flapper valve without increasing the outer diameter. 
   Though described in specific terms using specific components, the invention is not limited to those components. Other elements may be interchangeably used, perhaps with slight modifications to account for variations. For example, valve types other than a flapper valve can be used. Also, the invention may have other applications in which it is desirable to apply tubing pressure that are within the scope of this invention. For example, tubing pressure may be used to inflate or actuate a packer or other downhole component. 
   Other methods of providing power for opening the flapper can be used with the flapper arrangement described herein. A nitrogen gas spring, a compressible liquid spring, a mechanical spring, an atmospheric bias spring, a rupture disc, a hydro-mechanical pressure pulse operated power module, or a smart actuator could be used to provide power to actuate the flapper valve. An indexing mechanism in conjunction with a nitrogen gas power spring, as described in U.S. Pat. No. 6,352,119, can be used to operate the flapper valve with appropriate modifications. 
   Although only a few example embodiments of the present invention are described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from the novel teachings and advantages of this invention. Accordingly, all such modifications are intended to be included within the scope of this invention as defined in the following claims. It is the express intention of the applicant not to invoke 35 U.S.C. § 112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.