A gas lift valve has a flow restrictor, a valve part on one side of the flow restrictor, a flow deflector and a tubular member on another side of the flow restrictor, and a flapper valve on the side of the flow restrictor where the tubular member is located, the flapper valve being adjacent to the tubular member. When fluid flows into the gas lift valve at sufficient pressure, the valve part opens, the fluid flows through the flow restrictor and acts on the flow diverter thereby moving the tubular member and opening the flapper valve. The tubular member extends though the opening the flapper valve covered.

CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application claims the benefit of the filing date of U.S. Provisional Application No. 60/956,069 filed Aug. 15, 2007, entitled “PRESSURE OPERATED NOZZLE VENTURI/FLAPPER GAS LIFT VALVE,” filed on Aug. 15, 2007, which is incorporated herein by reference to the extent permitted by law. 
    
    
     TECHNICAL FIELD 
     The present application generally relates to the field of valves used in wells, and in particular, gas lift valves used in hydrocarbon wells. 
     BACKGROUND 
     Fluids are located underground. The fluids can include hydrocarbons (oil) and water, for example. Extraction of at least the oil for consumption is desirable. A hole is drilled into the ground to extract the fluids. The hole is called a wellbore and is oftentimes cased with a metal tubular structure referred to as a casing. A number of other features such as cementing between the casing and the wellbore can be added. Also, completions tubing and devices can be located inside the casing. The wellbore can be essentially vertical, and can even be drilled in various directions, e.g. upward or horizontal. 
     Once the wellbore is cased, the casing is perforated. Perforating involves creating holes in the casing thereby connecting the wellbore outside of the casing to the inside of the casing. Perforating involves lowering a perforating gun into the casing. The perforating gun has charges that detonate and propel matter through the casing thereby creating the holes in the casing and the surrounding formation and helping formation fluids flow from the formation and wellbore into the casing. 
     Sometimes the formation has enough pressure to drive well fluids uphole to surface. However, that situation is not always present and cannot be relied upon. Artificial lift devices are therefore sometimes needed to drive downhole well fluids uphole, e.g., to surface. 
     One such artificial lift device is a gas lift. A gas lift forces gas downhole and into the well fluids to lower the density of the well fluids thereby assisting lifting to the surface. Involved with gas lifts can be, for example, gas lift valves. 
     SUMMARY 
     An embodiment of features in the present application can include a gas lift valve, comprising: 
     a longitudinally extending tubular body defining an inner volume and an inner diameter; 
     a flow restrictor within the tubular body defining an opening there through having an inner diameter that is smaller than the inner diameter of the tubular body, thereby defining a first side of the flow restrictor and a second side of the flow restrictor; 
     a valve part located on the first side of the flow restrictor, the valve part being movable between a first position and a second position, the first position being in contact with the flow restrictor thereby restricting flow through the flow restrictor, and the second position not being in contact with the flow restrictor and allowing flow though the flow restrictor, the valve part being actuated by pressure on the first side of the flow restrictor; 
     an opening in the tubular body fluidly connecting an outside of the gas lift valve to an inside volume of the gas lift valve on the first side of the flow restrictor; 
     a longitudinally extending tubular device located inside the tubular body on the second side of the flow restrictor, the tubular device being longitudinally movable inside the tubular body; 
     a flow deflector located on the second side of the flow restrictor, the flow deflector being mechanically connected with the tubular device so that the flow deflector and the tubular body move in tandem; 
     a flapper valve located within the tubular body and adjacent to an end of the tubular device that is distal from the flow restrictor, the flapper valve having a first closed position wherein the flapper valve covers an opening though the tubular body, and a second open position wherein the flapper valve allows flow though the tubular body; wherein 
     when in the first position the tubular device is proximate to the flow restrictor thereby allowing the flapper valve into the first closed position covering the opening and when the tubular device is in the second position the tubular device extends though the opening and is distal to the flow restrictor thereby preventing the flapper valve from moving to the first closed position. 
     Other systems, methods, features, and advantages will be or will become apparent to one with skill in the art upon examination of the following figures and detailed description. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  is a schematic diagram of a valve shown in a closed position. 
         FIG. 2  is a schematic diagram of the valve of  FIG. 1 , shown in a half-open position. 
         FIG. 3  is a schematic diagram of the valve of  FIG. 1 , shown in an open position. 
         FIG. 4  is a schematic diagram of a valve shown in a closed position. 
         FIG. 5  is a schematic diagram of the valve of  FIG. 4 , shown in a half-open position. 
         FIG. 6  is a schematic diagram of the valve of  FIG. 4 , shown in an open position. 
         FIG. 7  is a flow diagram depicting the flow path of injection gas or fluid in the valve of  FIG. 3  or  FIG. 6 . 
     
    
    
     DETAILED DESCRIPTION 
     While embodiments will be described below with reference to the accompanying drawings, the specific structures and descriptions which follow are illustrative and exemplary of a broad scope, and are not to be construed as limiting embodiments. 
     As used here, the terms “above” and “below”; “up” and “down”; “upper” and “lower”; “upwardly” and “downwardly”; and other like terms indicating relative positions above or below a given point or element are used in this description to more clearly describe some embodiments. However, when applied to equipment and methods for use in wells that are deviated or horizontal, such terms may refer to a left to right, right to left, or diagonal relationship as appropriate. 
     A gas lift valve can operate or actuate (open and close) by a pneumatic process that allows pumped or injected lift gas or fluid to mix with crude oil or well fluid in a production tubing, thereby reducing the density of the crude oil or well fluid, and enhancing the production rate of the well. The injection gas or fluid is provided to an annulus between the production tubing and wellbore, and injected into the valve via one or more mandrels (e.g., side pocket) distributed along the production tubing. The valve controls the flow of the injection gas or fluid as it mixes with crude oil or well fluid in the production tubing. 
     When the annulus pressure of the injection gas or fluid exceeds a predefined threshold, the valve opens to allow the injection gas or fluid to be injected into the production tubing. When the annulus pressure is below the threshold, the valve is closed, thus at least substantially preventing injection gas or fluid from being injected into the production tubing. Gas lift valves can include a bellows-type actuation device that uses a combination of forces from the production tubing and annulus to regulate and selectively open or close the valve, often using a square edged orifice choke mechanism or a venturi style orifice. 
     Gas lift valves can include a reverse-flow check valve mechanism, often of the velocity check-type, to prevent well fluids from flowing in a reverse direction through the valve. However, a reverse-flow check valve mechanism can be relatively unprotected from the injection gas or fluid since they are included within the flow path, and thus can be subject to unacceptable erosion, corrosion, and other conditions that lead to gas leakage over time, causing hydrocarbons to be inadvertently released into the environment when well shut-in is required. 
     Accordingly, some embodiments described herein relate to a valve with a long-term, positive sealing system to provide systems with zero or minimal gas release when the system is closed. 
       FIGS. 1-3  depict schematic diagrams of a gas lift valve  100 .  FIG. 1  shows the valve  100  in a closed position. The valve  100  includes a ball stem and bellows assembly  110 , venturi orifice  120 , hydraulic system  130 , tubular device  140 , flapper system  150 , and flow-thru latch  160 . The ball stem and bellows assembly  110  is positioned at one end of the valve  100 . The ball stem and bellows assembly  110  includes a ball stem  11   2 , which interfaces with the venturi orifice, and bellows  114 . The bellows  114  is filled with nitrogen charged gas. The ball stem  112  and bellows  114  are connected to form the ball stem and bellows assembly  110 , which is moveable as a single unit. 
     The tip of the ball stem  112  may be positioned to interface with an entrance of the venturi orifice  120 . The position of the ball stem and bellows assembly  110  relative to the entrance of the venturi orifice  120  determines whether the valve  100  is open or closed, i.e., whether injection gas or fluid is allowed to flow through the valve  100 . As described below in more detail, when the tip of the ball stem  112  interfaces with the entrance of the venturi orifice  120  so as to close the passageway, injection gas or fluid is prevented from flowing through the valve  100 . Conversely, when the tip of the ball stem  112  is not integral with the entrance of the venturi orifice  120 , the valve is to some extent open, and injection gas or fluid may flow through the valve  100 . The venturi orifice  120  is shaped to allow pressure to be reduced at a stable rate, which is advantageous in a variety of applications, e.g., increasing flow through the orifice. Other orifices, such as a square edge orifice, may also be used. 
     The end of the venturi orifice  120  opposing the entrance is in communication with the hydraulic system  130 . The hydraulic system  130  includes tubular device bellows  132 ,  134 . The tubular device bellows  132 ,  134  are filled with liquid silicon, and are in communication with each other. The hydraulic system  130  provides a force on the tubular device  140  when the tubular device bellows  132 , 134  expand and contract. Other hydraulic pressure systems may be used in place of, or in addition to, the use of tubular device bellows  132 , 134 , such as a system utilizing a piston. The illustrative hydraulic system  130  utilizing tubular device bellows  132 ,  134  operates like a piston. The hydraulic system  130  is bounded by a flow channel  136 , which transports the injection gas or fluid from the venturi orifice  120  to the tubular device  140 . 
     The end of the hydraulic system  130  opposing the venturi orifice  120  is connected to the tubular device  140 . The tubular device  140  slides within the valve  100  to allow the flapper system  150  to open and close. The tubular device  140  is encased by a spring  142 , which when pressed upon, allows the tubular device  140  to translate. The spring  142  biases the tubular device  140  toward the venturi orifice  120 . When the valve  100  is in the closed position, as in  FIG. 1 , the tubular device  140  is pressed against the flapper system  150 , with the flapper system  150  blocking the flow path of the injection gas or fluid, preventing the tubular device  140  from translating along the axis of the valve  100 , and sealing the valve  100 . 
     The flapper system  150  is a type of reverse-flow check valve mechanism, serving to prevent well fluids from flowing in a reverse direction through the valve  100 . The flapper system  150  may include a flapper  150 , soft seat  152 , and hard seat  154 . The seats  152 ,  154  of the flapper system  150  are positioned outside of the flow path and tubular device  140 . Thus, when the tubular device  140  is moved to the left in the figures, the flapper  150  and seats  152 ,  154  are not subjected to the flow of the injection gas or fluid, which causes deterioration. In this regard, the flapper system  150  can provide a long-term, positive valve closure and sealing, with zero or minimal gas release after its closure. 
     In the illustrative example, the flapper  152  is formed of a metallic material, and is opened and closed using a hinge. The soft seat  154  is formed of a non-metallic material, such as a polymer. The hard seat  156  is formed of a metallic material. The optional soft seat  154  allows for sealing at minimal pressure differentials. One having ordinary skill in the art will appreciate that alternative materials may be used. In the illustrative example, the primary sealing is the metal-to-metal contact between the flapper  152  and the hard seat  156 . The housing of the flapper system  150  is connected to the flow-thru latch  160 , which is positioned on the end of the valve  100  opposing the ball stem and bellows assembly  110 . When the valve  100  is in an open position, injection gas or fluid flows through the flow-thru latch and into the production tubing, where it mixes with crude oil or other fluid. 
     The operation of the valve  100  will now be described. As described above, the illustrative valve  100  controls the flow of injection gas or fluid that is mixed with crude oil or well fluid in a production tubing to reduce the density of the crude oil or well fluid, thus enhancing the production rate of the well. The injection gas or fluid is provided to the valve  100  via an annulus between the production tubing and well. Alternatively, the injection gas or fluid could be provided from control line connected with surface. The valve  100  connects to the production tubing via one or more mandrels distributed along the line. 
     The injection gas or fluid enters the valve  100  through inlet  170 . Seals  180  provide the valve  100  with an isolation area between the seals  180 , channeling the injection gas or fluid to the inlet  170 . The bellows  114  of the ball stem and bellows assembly  110  may be filled, for example, with nitrogen charged gas. When the pressure of the injected gas or fluid exceeds the pressure in the nitrogen charged bellows  114 , the nitrogen charged bellows contracts, and the ball stem  112 , moving in conjunction with the bellows  114 , is positioned so that the injection gas or fluid is able to enter the venturi orifice  120 . Conversely, when the pressure of the injected gas or fluid is less than the pressure of the nitrogen charged bellows  114 , the nitrogen charged bellows  114  expands, and the ball stem  112  mates with the opening of the venturi orifice  120 , preventing the injection gas or fluid from entering the venturi orifice  120 . 
     When the valve  100  is in the closed position, as depicted in  FIG. 1 , no injection gas or fluid flows through the venturi orifice  120 . With no flow through the venturi orifice  120 , the hydraulic system  130  is not actuated. In this state, the tubular device  140 , connected to the hydraulic system  130 , is positioned in the valve  100  towards the end with the ball stem and bellows assembly  110 , as depicted in  FIG. 1 . The flapper system  150  is closed, with the flapper  152  being in the path of the tubular device, positively sealing the valve  100 . With the flapper system  150  closed, the valve is protected from crude oil or well fluid flowing in the valve in the reverse direction from the flow path of the injection gas or fluid. 
       FIG. 2  depicts a schematic diagram of the valve of  FIG. 1  when the valve  100  is in a half-open position. In this state, the pressure of the injected gas or fluid exceeds the pressure in the nitrogen charged bellows  114 , moving the ball stem  112 , in conjunction with the contracted bellows  114 , away from the entrance of the venturi orifice  120 , although the pressure of the injected gas or fluid is not so great as to completely avoid obstructing the entrance. 
     The injection gas or fluid flows through the venturi orifice  120  and actuates the hydraulic system  130 . The entrance area of the hydraulic system, operating as a piston, may include a fluid filtering system to minimize the intrusion of contaminants to the operating piston sealing systems, thereby providing an increased sealing system operational life. Potential forms of filtering include sintered metal and wire mesh systems. 
     The flow from the venturi orifice  120  causes the tubular device bellows  134  of the hydraulic system  130  to contract, thereby forcing fluid into the tubular device bellows  132  which causes the tubular device bellows  132  to expand, resulting in a net translational expansion of the bellows  132 ,  134 . Consequently, the hydraulic system  130 , which is connected to the tubular device  140 , forces the tubular device  140  to translate axially within the valve  200 , in the direction towards the flapper assembly  150 . After the injection gas or fluid leaves the venturi orifice and actuates the hydraulic system  130 , the injection gas or fluid disperses through a flow channel  136  encasing the hydraulic system  130 , and then recombines as it enters the tubular device  140 . 
     The hydraulic system  130  including the tubular device bellows  134  operating as a piston and may contain one or more sealing elements or systems in one or more locations of its length. The sealing elements may be dynamic or static in nature, and may be of a metal, elastomeric, or plastic material, of a combination thereof. The sealing elements may be configured as o-rings, t-rings, or other pressure energized or non-pressure energized sealing designs. 
     The translation of the tubular device  140  can open the flapper system  150 . Alternatively, the flow can open the flapper valve. Alternatively, the tubular device  140  and the flow can together open the flapper system  150 . As shown in  FIG. 2 , the valve  100  is only partially open, and so the pressure actuating the hydraulic system  130 , and the translation of the tubular device  140 , are consequently not at a maximum. Accordingly, as depicted in  FIG. 2 , in this state the flapper system  150  is partially open, with the tubular device  140  forcing it open part way. The closing force of the valve  100  may be a mechanical spring or a pressure containing chamber such as a bellows or a combination thereof. An additional closure motivator is a pressure differential on the hydraulic system  130  in the direction to allow the flapper  152  to shift to the closed position via its torsion spring. 
     While the flapper system  150  is partially open, the valve  100  is protected from crude oil or well fluid from the production tubing flowing through the valve  100  in the reverse direction because the tubular device  140  is seated integral with the housing of the valve  100 . With the flapper system partially open  150 , the injection gas or fluid is able to traverse the flow-thru latch  160  and ultimately combine with crude oil or well fluid in the production tubing. 
       FIG. 3  depicts a schematic diagram of the valve of  FIG. 1  when the valve  100  is in an open position. In this state, the pressure of the injected gas or fluid exceeds the pressure in the nitrogen charged bellows  114  to the extent that the ball stem  112  is positioned away from the entrance of the venturi orifice  120  to allow the injected gas or fluid to enter. As described above, the pressure of the injection gas or fluid that has traversed the venturi orifice  120  actuates the hydraulic system  130 . In this state, the combination of the tubular device bellows  132 , 134  causes the tubular device  140  to translate through to the flapper  142  and completely open the flapper system  150 . The injection gas or fluid flows through the tubular device  140 , and the valve  100  is protected from reverse-flowing crude oil or well fluid by the integral tubular device seating within the housing of the valve  100 . From the tubular device  140 , the injection gas or fluid traverses the flow-thru latch  160  and ultimately combines with crude oil or well fluid in the production tubing. 
       FIGS. 4-6  depict schematic diagrams of a gas lift valve  200  according to an embodiment.  FIG. 4  shows the valve  200  in a closed position. The valve  200  includes a ball stem and bellows assembly  110 , venturi orifice  120 , flow deflecting system  230 , tubular device  140 , flapper system  150 , and flow-thru latch  160 . Aside from the configuration and operation of the flow deflecting system  230 , the remaining components of the valve  200  may be identical to corresponding components described with respect to illustrative valve  100 . 
     The exit of the venturi orifice  120  is in communication with the flow deflecting system  230 . The flow deflecting system  230  includes a flow deflector, e.g., a dart  235 , that is shaped to obstruct/deflect the flow of the injection gas or fluid. The dart can have a rounded shape, but can also have many other profiles. The dart  235  is connected to the tubular device  140 . When the flow deflecting system  230  is subjected to the flow of the injection gas or fluid, the dart  235  provides a force on the tubular device  140 , causing it to translate axially within the valve  200 , and allowing the tubular device  140  to open and close the flapper system  150 . Other flow deflecting systems may be used in place of, or in addition to, the use of the dart  235 . 
     In  FIG. 4 , the pressure of the injected gas or fluid is less than the pressure in the nitrogen charged bellows  114 , and thus the valve  200  is closed. In this state, the ball stem  112  is mated with the entrance of the venturi orifice  120 , preventing the injection gas or fluid from flowing throughout the valve  200 . In this state, the flow deflecting system is not actuated, the tubular device is positioned towards the end of the valve  200  with ball stem and bellows assembly  110 , and the flapper system  150  is closed. 
       FIG. 5  depicts a schematic diagram of the valve  200  of  FIG. 4  when the valve  200  is in a half-open position. As described with respect to  FIG. 2 , in this state the pressure of the injected gas or fluid exceeds the pressure in the nitrogen charged bellows  114 , and the ball stem  112  is positioned so that the injection gas or fluid is able to enter the venturi orifice  120 , although the ball stem  112  is not completely clear from the entrance. The injection gas or fluid flows through the venturi orifice  120 , with the pressure being reduced at a stable rate, and actuates the flow deflecting system  230 . The flow deflects from dart  235 , providing the force for the tubular device  140  to translate axially within the valve  200  in the direction towards the flapper system  150 . As described above, the translation of the tubular device  140  and or the flow partially opens the flapper  152 , and the injection gas or fluid traverses the flow-thru latch  160  and ultimately combines with crude oil or well fluid in the production tubing. 
       FIG. 6  depicts a schematic diagram of the valve of  FIG. 4  when the valve  200  is in an open position. As described above with respect to  FIG. 3 , in this state the pressure of the injected gas or fluid exceeds the pressure of the nitrogen charged bellows  114 , and the ball stem  112  is positioned sufficiently away from the entrance of the venturi orifice  120  to allow the injected gas or fluid to enter more freely than as depicted in  FIG. 5 . As described above, the injection gas or fluid flows through the venturi orifice  120 , with the pressure being reduced to a stable rate, and actuates the flow deflecting system  230 , providing the force for the tubular device  140  to translate axially and fully open the flapper  152 , and allowing the injection gas or fluid to traverse the flow-thru latch  160  and ultimately combine with crude oil or well fluid in the production tubing. 
       FIG. 7  is a flow diagram depicting the flow path  300  of the injection gas or fluid as it traverses the valve  100  or valve  200 , as described above. The injection gas or fluid enters valve  100  or valve  200  through inlet  170  (step  310 ). If the pressure of the injection gas or fluid exceeds the pressure of the nitrogen charged bellows  114 , the injection gas or fluid flows through the venturi orifice  120  (step  320 ). If, however, the pressure of the injection gas or fluid does not exceed the pressure of the nitrogen charged bellows  114 , the injection gas or fluid does not flow through the venturi orifice  120  (step  330 ) because the entrance is blocked by the ball stem  112 , closing the valve  100 . 
     Where the hydraulic system  130  is used, from the venturi orifice  120  the injection gas or fluid flows through flow channel  136  encasing the hydraulic system  140  (step  340 ). Where the flow deflecting system  230  is used, from the venturi orifice  120  the injection gas or fluid is deflected by and around the dart  235  (step  350 ). In both situations, the injection gas or fluid next flows through the tubular device  140  (step  360 ) and passes through the flapper system  150 . The injection gas or fluid then flows through the flow-thru latch  160  (step  370 ), ultimately mixing with crude oil or well fluid in the production tubing. 
     The illustrative valves  100 ,  200  described above are able to be independently and selectively operated, with benefits similar to those of a surface controlled subsurface safety valve (SCSSV). The long-term, positive sealing flapper system  150  allows zero or minimal gas or fluid release upon closure, thereby providing a cost-effective, positive closing valve to dramatically reduce the potential for inadvertent hydrocarbon releases into the environment when well shut-in is required. Moreover, the annulus pressure operated designs are retro-fitable into wells where applicable and serviceable side-pocket mandrels are present. 
     The above embodiments and descriptions allow the illustrative valves  100 ,  200  to open and close via an applied pressure and independently of a choke, or choke-like, flow-entering, pressure differential device. Moreover, the valves  100 ,  200  can use hydraulic pressure applied to either open or close the valves via one or more control lines or conduits that are connected from a hydraulic power source through independent conduits to effect movement of a piston assembly integral to the valve, which either moves the mechanism to the open or closed position depending upon the conduit selected or the count of the pressure cycles on the conduit. The valves  100 ,  200  can operate from a down hole casing pressure source or from a single or dual control line surface controlled conduit. The valve system can be used in all standard wireline retrievable gas lift configurations and is capable of installation in typical industry standard side pocket mandrels. The system can be installed in all standard gas lift completion configurations. 
     While various embodiments have been described, it will be apparent to those of skill in the art that many more embodiments and implementations are possible.