Patent Abstract:
A downhole differential flow control valve is provided that utilizes a differential pressure area having one pressure area on which the wellbore pressure acts and a second area different from the first area on which pressure in the tubing acts. The differential area reduces the load in which the spring is required to exert a closing force in the valve. Thus, a coil spring can be used to improve the closing speeds of the valve.

Full Description:
BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     The present invention relates to oil field downhole tools. Particularly, the invention relates to flow control valves used in tubulars in a wellbore. 
     2. Background of the Related Art 
     In the operation of oil and gas wells, it is often necessary to enter the wellbore to perform some downhole task. Tool retrieval, formation stimulation and wellbore clean out are all examples of tasks carried out in a live well to improve production or cure some problem in the wellbore. Typically, a tubular of some type is inserted into a wellbore lined with casing or is run in production tubing to perform these tasks. Because so many wells are located in remote locations, coil tubing is popular for these operations because of its low cost and ease of use compared to rigid tubulars. 
     Selectively pumping a pressurized liquid or gas into a live well presents some challenges regardless of the use of rigid or coil tubing. For example, most operations require the fluid to be pumped at a predetermined depth in order to effect the right portion of a formation or to clean the effected area of the wellbore. In order to maintain the liquid in the tubular until a predetermined time, a valve proximate the downhole end of the tubular string is necessary to prevent the fluid from escaping until the operation begins. Additionally, to prevent loss of pressure in the tubular, the valve must open and close rapidly. The rapidity of operation is especially critical when coil tubing is used, because the maintenance of pressure within the coil tubing is necessary to prevent the tubing from collapsing due to adjacent pressure in the wellbore. 
     FIG. 1 is an exemplary well  10  which could be the subject of a downhole cleaning, removal or formation perforation operation. Typically, the wellbore hole is cased with a casing  12  that is perforated to allow pressurized fluid to flow from the formation  18  into the wellbore  15 . To seal the mouth of the well, a wellhead  20  is mounted at the upper end of the wellbore. The wellbore in FIG. 1 is shown with a string of coil tubing  14  inserted therein. As herein described, the tubing is typically filled with a liquid or gas, such as water, foam, nitrogen or even diesel fuel for performing various operations in the well, such as cleaning or stimulating the well. 
     The weight of the fluid in the tubular member  14  creates a hydrostatic pressure at any given depth in the tubular member. The hydrostatic pressure in the tubing at the top surface is approximately zero pounds per square inch (PSI) and increases with depth. For example, the hydrostatic pressure caused by the weight of the fluid in the tubing in a 10,000 feet deep well can be about 5,000 PSI. In many instances, the hydrostatic pressure at a lower zone  22  of the tubing is greater than the wellbore pressure at a similar depth in the wellbore zone  24 . Thus, a flow control valve  16  is used to control or stop the flow of the fluid from the tubular member  14  into the wellbore  15 . 
     Even though the hydrostatic pressure in the tubing can be greater than the wellbore pressure near the bottom of the well, the opposite effect may occur at the top of the well. If the wellbore pressure is high, for example, in a gas well, the wellbore pressure at the top of the well can be several thousand PSI above the relatively low hydrostatic pressure in the tubing at the top of the well. It is generally known to well operators that a wellbore pressure greater than about 1,500 PSI can crush some tubing customary used in well operations, such as coil tubing. Thus, operators will pressurize the tubing  14  with additional pressure by pumping into the coil tubing to overcome the greater wellbore pressure at the top of the wellbore. In some high differential pressure applications, fluid must be pumped continuously through the tubular to maintain a pressure at the top of the tubular and waste the fluid into the wellbore because of the inability of a valve to control the high differential pressures. 
     In other applications, such as in lower differential pressure applications, a flow control valve can be mounted to the end of the tubular to attempt to adjust for the differences between the downhole hydrostatic pressures and associated wellbore pressures. The valve allows the wellbore pressure to counteract the hydrostatic pressure in conjunction with an upwardly directed spring force. FIG. 2 is a schematic of one exemplary differential flow control valve. The valve  26  is disposed at the lower end of a tubing (not shown) and has an upper passageway  28  through which tubing fluid can flow. The lower passageway  29  of the valve  26  allows wellbore fluid at a wellbore pressure to enter the valve  26 . A poppet  30  is disposed within the valve  26  and engages a seat  32 . Belleville washers  34 , acting as a disk shaped spring, are disposed below the poppet  30  to provide a sufficient upward bias to override the hydrostatic pressure in the passageway  28 . When the sealing member is sealingly engaged with the seat  32 , the two passageways are fluidly disconnected from each other. When the pressure is increased sufficiently to override the upward bias, the sealing member  30  separates from the seat  32  and the two passageways are in fluid communication. The valve  26  operates on differential pressures in that the wellbore pressure provides an upward force on the poppet in addition to the Belleville washers  34 . 
     However, it has been discovered that while the Belleville washers can open quickly, the washers close slowly, i.e., operate with different opening and closing speeds, known as a hysteresis effect. Thus, the valve  26  can be opened to flow pumped fluid from the tubing  14  into the wellbore  15  (shown in FIG.  1 ), but is insufficient to quickly close the valve to retain pressure in the tubing once a pump has stopped pumping fluid into the tubing to allow the valve to close. Thus, the differential pressure at the upper portion of the tubing is not maintained and the tubing can be deformed or crushed when a high differential pressure exists between the inside of the tubing and the surrounding wellbore. Other manufacturers, such as Cardium Tool Services, use a coil spring in a hydrostatic valve, but enclose the coil spring in a sealed chamber that is not open to varying pressures and thus not a differential flow control valve. Such valves can collapse and seize when high differential pressures are encountered. 
     It would be desirable to use a coil spring in a differential flow control valve, which has less hysteresis effects and generally equal opening and closing speeds, but the required forces generated from a typical coil spring in the relatively small diameters of the valve are insufficient to simply replace the Belleville washers. Thus, the use of a coil spring is not practical in a typical differential flow control valve. 
     Thus, there exists a need for a differential flow control valve which is more responsive to hydrostatic pressures, especially in applications having a high hydrostatic pressure compared to a surrounding wellbore pressure. 
     SUMMARY OF THE INVENTION 
     A downhole differential flow control valve is provided that utilizes a differential pressure area having one pressure area on which the wellbore pressure acts and a second area different from the first area on which pressure in the tubing acts. The differential area reduces the load in which the spring is required to exert a closing force in the valve. Thus, a coil spring can be used to improve the closing speeds of the valve. 
     In one aspect, a valve is provided for use in a wellbore, the valve comprising a body, a piston disposed in the body for engaging a valve seat disposed in the body, a biasing member producing a spring force to urge the sealing end of the piston into engagement with the valve seat, whereby the valve opens when the second force exceeds a combination of the spring force and the effective force. In another aspect, a differential pressure control valve is provided for oil field applications, comprising a valve housing having a housing passageway, a valve seat coupled to the housing and having a seat passageway disposed therethrough, a sealing member at least partially disposed within the valve housing and selectively engagable with the valve seat, a bias cavity in fluid communication with the seat passageway; and a bias member coupled to the sealing member that biases the sealing member toward the valve seat. In another aspect, a method of actuating a differential flow control valve is provided, comprising allowing a sealing member to engage a seat on a first piston surface, allowing a first fluidic pressure to apply a first force on at least a first portion of the first piston surface while allowing the first fluidic pressure to apply a greater force on a second piston surface distal from the first piston surface, biasing the sealing member toward the seat with a bias member having a cavity in fluidic communication with the first fluidic pressure, and applying a second fluidic pressure to at least a second portion of the first piston surface to open the valve, wherein a cross sectional area of the second portion is greater than a cross sectional area of the first portion. 
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS 
     So that the manner in which the above recited features, advantages and objects of the present invention are attained and can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to the embodiments thereof which are illustrated in the appended drawings. 
     It is to be noted, however, that the appended drawings illustrate only typical embodiments of this invention and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments. 
     FIG. 1 is a schematic of a well. 
     FIG. 2 is a schematic cross sectional view of an exemplary differential flow control valve. 
     FIGS. 3A and 3B depict a schematic cross sectional view of a valve assembly. 
     FIG. 4 is a detailed cross sectional schematic of a portion of the valve. 
     FIG. 5 is a cross sectional schematic of a force diagram. 
    
    
     DESCRIPTION OF THE PREFERRED EMBODIMENT 
     FIGS. 3A and 3B depict a cross sectional schematic view of one embodiment of the valve assembly  50 . The assembly is shown with the upper end, as the valve would generally be positioned in a wellbore, on the left side of the figure. A top subassembly  52  is coupled to a housing enclosure  56  on an upper end of the valve assembly  50 . A bottom subassembly  54  is coupled to the enclosure  56  on a lower end of the valve assembly  50 . A seat assembly  58  is disposed between the subassemblies and internal to the enclosure  56 . A sealing member, herein a “stem”  60 , sealably engages the seat assembly  58 . The seat assembly  58  includes a passageway  59 , formed therethrough, in fluidic communication with a passageway through the bottom subassembly  54 . Similarly, the stem  60  includes a passageway  61 , formed therethrough, in fluidic communication with the passageway  59 . A stem holder  62  is disposed circumferentially around the stem  60  where the stem is slidably and sealably engaged with the stem holder  62 . A spring guide  64  is disposed above the stem holder  62  and surrounds a portion of the stem  60  on one end and has an elongated center rod disposed upwardly. A bias member, such as a coil spring  66 , is disposed about the spring guide  64  in a spring cavity  67 . A spring casing  68  surrounds the spring  66  and the spring guide  64  and is sealably engaged on a lower end to the stem holder  62 . A spring holder  70  is disposed above the spring  66  and forms a bearing surface for an upper end of the spring  66 . A roller ball  72  engages an upper end of the spring holder  70 . 
     An adjustor sleeve is disposed above the roller ball  70 , where the roller ball reduces friction between an adjustor sleeve  74  and the spring holder  70 . The lower end of the adjustor sleeve  74  can also be threadably engaged with an upper end of the spring casing  68  and sealed thereto. An upper end of the adjustor sleeve  74  can be threadably engaged with a cap  78 . The cap  78  forms a sealed cavity using seal  81  between the cap  78  and the adjustor sleeve  74 . An adjustor  76  is disposed within the cap  78 . The adjustor  76  has external threads which threadably engage internal threads of the adjustor sleeve  74 . The adjustor  76  can be rotated so that the adjustor traverses longitudinally and applies a force to the spring  66  to vary the compression or expansion of the spring. A cavity  79  is formed above the cap  78  and is open in fluidic communication with the mouth  53  of the top subassembly  52 . 
     A mouth  53  of the top subassembly  52  is fluidicly coupled to the inside of the tubing  14 , shown in FIG. 1, to form a housing passageway therethrough. Thus, pressure existing in the tubing  14  (herein P T ) adjacent the valve assembly  50  can be transmitted through the mouth  53  through the top subassembly  52  into the chamber  79 . The pressure can then be transmitted into an annulus formed between the inside diameter of the enclosure  56  and the outside diameters of the various components of the valve, including the cap  78 , the adjustor sleeve  74  and the spring casing  68 . The pressure P T  then can exert a force on the stem  60  as disclosed in reference to FIGS. 4-5. 
     From the bottom of the valve, similarly the mouth  55  of the bottom subassembly  54  is in fluidic communication with the wellbore  15  (shown in FIG. 1) and the wellbore pressure (herein P W ) adjacent the valve assembly  50 . The pressure in the wellbore P W  is transmitted through the mouth  55  of the bottom subassembly  54  and through the passageway  59  in the seat assembly  58 . The pressure Pw creates a force on the lower end of the stem  60 . Further, the pressure P W  is transmitted through the passageway  61  of the stem  60  and exerts a pressure on the top surface of the stem adjacent the spring guide  64 . 
     A port  90  is disposed through the stem  60  and is fluidicly coupled to the passageway  61  of the stem  60 , so that pressure P W  is transmitted into and through port  90 . Port  90  is fluidicly coupled to the spring cavity  67  by a space between the stem  60  and the stem holder  62  and by an annulus between the spring guide  64  and the spring casing  68 . Thus, the spring cavity  67 , the passageway  61  of the stem  60 , the passageway  59  of the seat assembly  58 , and the mouth of the bottom subassembly  54  are in fluidic communication to the pressure P W  in the wellbore. The fluidic communication allows the valve assembly  50  to adjust to varying pressures in the wellbore at different depths and at different production pressures. 
     FIG. 4 is a detailed cross sectional schematic of the valve assembly  50 . A bottom subassembly  54 , shown in FIG. 3B, is coupled to a housing enclosure  56  and may be sealed thereto. A seat assembly  58  includes a seat support  82  and a replaceable seat  84 . The seat assembly includes a passageway  59  formed herein. An annulus between the seat  84  and the seat support  82  may be sealed by seal  86 . A stem  60  disposed above the seat  84  has a lower seating surface  88  that can contact an upper surface of the seat  84 . A stem holder  62  circumferentially surrounds a portion of the stem  60  and may be slidably and sealably engaged to the stem with a seal  92 . The stem holder  62  can be sealably engaged with a spring casing  68  using a seal  94 . The housing enclosure  56  surrounds the stem  60 , the stem holder  62  and spring casing  68 , forming an annulus therebetween. The stem  60  includes a passageway  61  formed therein that is in fluid communication with the passageway  59  of the seat  84  and seat support  82  and the passageway through the bottom subassembly  54 . Thus, the interior portions of the above mentioned members are in fluidic communication to the wellbore pressure P W . A port  90  is disposed into the stem  60  and is in fluidic communication with the passageway  61  of the stem  60  and wellbore pressure P W . The spring cavity  67  is in fluidic communication with the port  90  and allows wellbore pressure P W  to be created therein. A spring guide  64  is disposed above the stem  60 . A spring  66  is disposed adjacent the spring guide  64 . Generally, spring  66  is a compression spring which exerts a downward force on the spring guide  64  and then to the stem  60 . A spring casing  68  surrounds the spring  66 , the spring guide  64  and the stem holder  62 . 
     Tubing pressure zone  100  is fluidicly coupled to fluid in the tubing through port  91  and the associated pressure P T . Pressure P T  occurs through the top sub  53  shown in FIG.  3 A and in the annulus between the enclosure  56  and the spring casing  68 . At least a portion of the exterior surface  99  of the stem  60  is exposed to the tubing pressure P T . When the stem  60  is lifted from the seat  84 , fluid flow can occur through the tubing and into the wellbore zone  28 , shown in FIG.  1 . Lower wellbore pressure zone  96  and upper wellbore pressure zone  98  are fluidicly coupled to fluid in the wellbore and the associated wellbore pressure P W.    
     It is believed that the wellbore pressure P W  exerts an upward force on the stem  60  at the seating surface  88 , acting as a piston surface, to a diameter D 2  approximately equal to one-half the distance between the outer and the inner diameters of the stem  60 , shown as diameter D 1  and D 3 , respectively. The upper portion  102  of the stem  60 , also acting as a piston surface, has a larger diameter D 1  than the diameter D 2 . Thus, the same pressure acting on the top of the stem  60  at diameter D 1  has a greater surface area compared to the area formed by diameter D 2  on which to act and creates a greater downhole effective force on the stem  60 . The diameter D 1  is shown as a consistent diameter inside and outside of the stem holder  62 . However, it is understood that the diameter could very such as a stepped diameter. Because the upper annular pressure zone  98  is exposed to the wellbore pressure P W , and because the cross sectional area formed by diameter D 1  is larger than the cross sectional area formed by diameter D 2 , the wellbore pressure P W  acting on diameter D 1  overcomes the upward forces created by the pressure P W  acting on the diameter D 2 . Thus, the stem is pressurized to a closed position where the stem  60  engages the seat  84  at the seating surface  88 . The spring  66  can also be used to supplement the downward force created by the wellbore pressure P W  by applying a spring force S F  to the spring guide  64  and then to the stem  60 . 
     Similarly, the tubing pressure P T  in the tubing pressure zone  100  acts on the outer circumference of the stem  60  between the seal  92  and the seating surface  88  to about the diameter D 2 . The resultant force created by P T  is an upwardly directed force acting on the difference in diameters between diameterD 1  and diameter D 2 . In a closed valve position, the combination of the spring force S F  and an effective force created by the wellbore pressure P W  acting on the upper piston surface  102  of the stem  60  well forces the stem  60  into sealing engagement with the seat  84  at the seating surface  88 . To open the valve, the tubing pressure P T  can be increased, so that the upward force created by P T  on the portion of the seating surface  88  between diameters D 1 , and D 2  overrides the downward force created by the spring  66  and the wellbore pressure P W  acting on the upper piston surface  102 . 
     FIG. 5 is a schematic force diagram of the forces acting on the stem  60 . On the left portion of the figure, at an upper end of the stem  60 , a spring force S F  acts on the upper piston surface  102 . Pressure P W  creates a pressure force on the cross sectional area between diameters D 1  and D 3 , where D 3  is the passageway  61  diameter of the stem  60 . On the seating surface  88 , P W  creates a force on the cross sectional area between D 2  and D 3 . Because pressure P W  counteracts the forces created between diameters D 2  and D 3  on each end, a net effective downward force is created on the cross sectional area defined betweenD 1  and D 2  on the upper piston surface  102 . 
     On the seating surface  88 , the tubing pressure P T  creates a net force resultant upward on the cross sectional area of the seating surface  88  defined between the diameterD 1  and D 2 . A net closing force can be defined by the equation F C =P W [(D 1 /2) 2 −(D 2 /2) 2 ]π+S F , where F S  equals a closing force and the other variables have been defined herein. A net opening force, in this example, directed upward toward the top of the wellbore would equal F O =P T [(D 1 /2) 2 −(D 2 /2) 2 ]π, where F O  equals the opening force. Thus, to close the valve, force F C  is greater than force F O  and, conversely, to open the valve, force F O  is greater than force F C . Generally diameter D 1  is greater than diameter D 2 . 
     The ability to use a coil spring or other springs exerting a relatively small force is enabled by controlling the differential areas between diameters D 1  and D 2 . The differential area can be defined as [(D 1 /2) 2 −(D 2 /2) 2 ]π. For example, a relatively small differential area between diameters D 1  and D 2  results in compensating for a large difference between pressures P W  and P T . The difference in pressures is multiplied by a relatively small differential area and results in a relatively small difference in resultant forces. Thus, spring force S F  may be relatively small to counteract relatively large pressure differences between the pressure P T  in the tubing  14 , shown in FIG. 1, and the pressure in the wellbore P W . As merely one example, and others are available, if the P T  equal 10,000 PSI, P W  equals 5,000 PSI and the differential area between diameters D 1  and D 2  equals 0.1 square inches, then the resultant spring force S F  required to override a 5,000 PSI difference in pressure would equate to merely 500 pounds. Similarly, with the same pressures, a differential area of 0.05 square inches would equate to a spring force of about 250 pounds to override the 5,000 PSI difference. 
     Other types of springs may be used and variations of the embodiments described herein are contemplated. For example, a gas spring can be used in addition to or in lieu of the coil spring. The gas spring can be a nitrogen filled cavity that exerts a downward force generally according to the formula PV=nRT for ideal gases where P is the pressure, T is the temperature, n is the number of moles, R is the universal gas constant and V is the volume. Thus, if downhole conditions are known, such as pressure and temperature, for a given volume, the gas spring can be precharged at a certain pressure and inserted downhole to a given position. The resultant effect is that the gas spring exerts a downward force on the stem  60  as described herein. In some embodiments, the gas charged cavity may operate in conjunction with a wellbore pressure P W  so that the differential pressure is maintained. 
     While foregoing is directed to the preferred embodiment of the present invention, other and further embodiments of the invention may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow. Further, the pressures described herein are approximate and have not been adjusted for friction losses. For example, the pressure in tubing P T  may have some friction loss resulting in a smaller pressure after traversing the flow circuit in the valve. However, the principles of valve operation remain the same as described herein.

Technology Classification (CPC): 4