Abstract:
A system is provided for unloading accumulated liquids and enhancing the recovery of gas from a reservoir having diminished pressure. An annulus between a tubing string and casing is isolated by a packer and continually pressurized with a slipstream of compressed gas while the well continues to produce. A unique valve positioned in the tubing string is shuttled between a production position in which production fluids are permitted to bypass the valve to the surface and a lift position in which the bypass is blocked and an unloading port is opened to vent high pressure annulus gas to the tubing string above the valve, lifting accumulated liquids with it. Preferably, the valve is actuated to the lift position by the impact of a plunger dropped from a lubricator at the wellhead, when the pressure in the annulus has reached a predetermined threshold. When the gas has been vented and the pressure in the annulus drops, the valve is actuated to the uphole production position as a result of the higher reservoir pressure.

Description:
FIELD OF THE INVENITON  
         [0001]    The present invention relates to apparatus and methods for lifting liquids from a wellbore during production of gas or oil and more particularly to lifting liquids from wellbores where the natural reservoir pressure has diminished over time.  
         BACKGROUND OF THE INVENTION  
         [0002]    It is well known that during the production of hydrocarbons, particularly from gas wells, the accumulation of liquids, primarily water, has presented great challenges to the industry. As the liquid builds at the bottom of the well, a hydrostatic pressure head is built which can become so great as to overcome the natural pressure of the formation or reservoir below, eventually “killing” the well.  
           [0003]    A fluid effluent, including liquid and gas, flows from the formation. Liquid accumulates as a result of condensation falling out of the upwardly flowing stream of gas or from seepage from the formation itself. To further complicate the process the formation pressure typically declines over time. Once the pressure has declined sufficiently so that production has been adversely affected, or stopped entirely, the well must either be abandoned or rehabilitated. Most often the choice becomes one of economics, wherein the well is only rehabilitated if the value of the unrecovered resource is greater than the costs to recover it.  
           [0004]    A number of techniques have been employed over the years to attempt to rehabilitate wells with diminished reservoir pressure. Some of these are using soap sticks, “pitting” the well occasionally by blowing the well down in a pit to atmospheric pressure, swabbing, injecting high pressure gas into the formation, lowering the end of the tubing string to the perforation, tapering the tubing string to a smaller inner diameter near the surface to increase the flow rate, optimizing tubing size to balance velocity and friction effects, waterflooding the formation to augment pressure depletion, insulating and heating the production tubing string to minimize condensation and liquid fallout and beam lifting.  
           [0005]    One common technique has been to shut in or “stop cock” the well to allow the formation pressure to build over time until sufficient to lift the liquids when the well is opened again. Unfortunately, in situations where the formation pressure has declined significantly, it can take many hours to build sufficient pressure to blowdown or lift the liquids, reducing the hours of production. Applicant is aware of wells which must be shut in for 12-18 hours in order to obtain as little as 4 hours of production time before the hydrostatic head again becomes too large to allow viable production.  
           [0006]    Two other techniques, plunger and gas lift, are commonly used to enhance production from low pressure reservoirs.  
           [0007]    A plunger lift production system typically uses a small cylindrical plunger which travels freely between a location adjacent the formation to a location at the surface. The plunger is allowed to fall to the formation location where it remains until a valve at the surface is opened and the accumulated reservoir pressure is sufficient to lift the plunger and the load of accumulated liquid to the surface. The plunger is typically retained at the wellhead in a vertical section of pipe and associated fitting called a lubricator until such time as the flow of gas is again reduced due to liquid buildup. The valve is closed at the surface which “shuts in” the well. The plunger is allowed to fall to the bottom of the well again and the cycle is repeated. Shut-in times vary depending upon the natural reservoir pressure. The pressure must build sufficiently in order to achieve sufficient energy, which when released, will lift the plunger and the accumulated liquids. As natural reservoir pressure diminishes, the required shut-in times increase, again reducing production times.  
           [0008]    Typically, a gas lift production system utilizes injection of compressed gas into production tubing to aerate the production fluids, particularly viscous crude oil, to lower the density and cause the resulting gas/oil mixture to flow more readily to the surface. The gas is typically separated from the oil at the surface, recompressed and returned to the tubing string. Gas lift methods can be continuous wherein gas is continually added to the tubing string, or gas lift can be performed periodically. In order to supply the large volumes of compressed gas required to perform conventional gas lift, large and expensive systems, requiring large amounts of energy, are required. Gas is typically added to the production tubing using gas lift valves directly tied into the production tubing or optionally, can be added via a second, injection tubing string. Complex crossover elements or multiple standing valves are required for implementations using two tubing strings, which add to the maintenance costs and associated problems.  
           [0009]    A combination of gas lift and plunger lift technologies has been employed in which plungers are introduced into gas lift production systems to assist in lifting larger portions of the accumulated fluids. In gas lift alone, the gas propelling the liquid slug up the production tubing can penetrate through the liquid, causing a portion of the liquid to escape back down the well. Plungers have been employed to act as a barrier between the liquid slug and the gas to prevent significant fall down of the liquid. Typically, the plunger is retained at the top of the wellhead during production and then caused to fall only when the well is shut in and the while the annulus is pressurized with gas. This type of combined operation still requires that the well be shut in and production be halted each time the liquid is to be lifted.  
           [0010]    Clearly, there is a need, in the case of wells having declining natural reservoir pressure, for apparatus and methods that would allow the energy within the annulus to be augmented for lifting the accumulated liquids in the well, without a requirement to shut in the well and halt production.  
         SUMMARY OF THE INVENTION  
         [0011]    In a broad aspect of the invention, a system is provided which enables unloading or lifting of liquids from a gas well to alleviate the associated hydrostatic pressure and thus enhance gas production from a tubing string, without the need to shut-in a well. The annulus is continuously charged with compressed gas to build energy which is periodically released to lift accumulated fluids, using a combination of plunger and gas lift techniques. The wellbore annulus is fitted with a packer to create an annular chamber which can be charged with gas for creating a large pressure differential compared to that present in the reservoir alone.  
           [0012]    A shuttle-type valve is located in the production tubing string and is positioned at the base of the wellbore adjacent the packer. The valve is operable between a production position, permitting production of fluids from the formation to the surface, and an unloading or lift position, wherein the gases within the annulus can be discharged through the tubing string, lifting any accumulated liquids to the surface.  
           [0013]    A steady slipstream of compressed gas is continuously fed to the packed off annulus while the well continues to produce. When the pressure in the annulus reaches a predetermined threshold, a plunger, which resides in a wellhead lubricator at the surface, is triggered to fall down the tubing string and through any collected liquid. Preferably, the plunger also contacts a valve stem in the valve, actuating the valve stem to a downhole lift position. In the lift position, ports in the valve which normally allow production are blocked and the ports to the annulus are opened, permitting the accumulated pressurized gases in the annulus to vent upwardly through the production tubing, lifting the plunger and the accumulated liquid with it. The plunger is carried up the production tubing with the liquid and gases to the wellhead lubricator where it is caught and held until the unloading cycle is repeated.  
           [0014]    The high pressure gas in the annulus vents until the pressure in the formation again exceeds that of the annulus. The higher formation pressure then acts on the valve stem to force it to an uphole production position, opening the production ports to resume production, and blocking the annulus ports so as to allow pressure to begin to accumulate in the annulus once more.  
           [0015]    In a preferred embodiment of the invention the valve assembly further comprises a landing spring assembly which acts to “cushion” the impact of the plunger on the valve assembly by absorbing excess force of the falling plunger. The landing assembly comprises an outer spring to absorb the excess energy and an inner spring to accept energy transferred from the outer spring to actuate the valve stem in the valve to the downhole position.  
           [0016]    Thus, in a broad aspect of the invention, a system is provided for enhancing gas recovery from a tubing string which extends down a wellbore into a reservoir having diminished pressure wherein the tubing string accumulates liquid, the system comprising:  
           [0017]    a packer between the wellbore and the tubing string for forming an annulus, isolated from the reservoir;  
           [0018]    a source to continuously build pressure within the annulus; and  
           [0019]    a valve positioned in the tubing string adjacent the packer which is actuated, preferably using a plunger, from a production position, wherein production ports are opened and fluidly connected by a bypass chamber in the valve between the reservoir to the tubing string above the valve for producing gas from the reservoir and one or more unloading ports connecting the annulus to the tubing string are blocked, to a lift position, wherein the production ports are blocked and the unloading ports are open for releasing high pressure gas stored in the annulus to the tubing string above the valve to lift and remove accumulated liquids from the tubing string.  
           [0020]    Preferably the valve is actuated to the lift position by the impact of a plunger falling down the tubing string and to the production position as a result of differential pressure between the vented annulus and the reservoir. Such a valve would comprise:  
           [0021]    a tubular housing having having an upper production port fluidly connected to the tubing string above the valve, a lower production port fluidly connected to the reservoir below the valve and an unloading port fluidly connecting the isolated annulus to the tubing string above the valve; and  
           [0022]    a valve stem having an uphole and a downhole piston and axially moveable within the housing between a first uphole production position wherein the uphole piston blocks the unloading port, the upper and lower production ports are fluidly connected and the downhole piston opens the reservoir to the lower production port, and a second downhole lift position wherein the downhole piston blocks the reservoir from the lower production port and the uphole piston opens the unloading port.  
           [0023]    The above described valve and system enable practice of a novel process described broadly as comprising the steps of: providing a packer between the wellbore and the tubing string for forming an annulus, the annulus being isolated from the reservoir, and a valve located in a bore of the tubing string adjacent the packer; pressurizing the annulus; opening one or more production ports for fluidly connecting the reservoir to the tubing string above the valve while blocking one or more unloading ports connecting the annulus to the tubing to flow reservoir gas; and blocking the production ports and opening the unloading ports to lift accumulated liquids out of the tubing string.  
           [0024]    Preferably, the blocking of the ports is accomplished by dropping a plunger down the tubing string so as to impact and actuate the valve from an uphole production position wherein the production ports are open and the unloading ports are blocked to a downhole lift position wherein the production ports are blocked and the unloading ports are open. The valve is preferably returned to the production position when the reservoir pressure exceeds the annulus pressure.  
       
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS  
       [0025]    [0025]FIG. 1 a  is a schematic representing the plunger-actuated gas lift production system of the present invention with the unloading valve in the production position;  
         [0026]    [0026]FIG. 1 b  is a schematic representing the plunger-actuated gas lift production system according to FIG. 1 a  with the unloading valve in the lift position;  
         [0027]    [0027]FIG. 2 a  is a schematic representing one embodiment of a conventional plunger;  
         [0028]    [0028]FIG. 2 b  is a schematic representing one embodiment of a conventional lubricator showing the catching mechanism and pneumatic controller;  
         [0029]    [0029]FIG. 3 is a detailed longitudinal cross-sectional view of an unloading valve of the present invention in the production position;  
         [0030]    [0030]FIG. 4 is a detailed longitudinal cross-sectional view of the unloading valve of FIG. 3 in the lift position;  
         [0031]    [0031]FIG. 5 is a detailed cross-sectional view of a poppet valve located in the unloading valve of FIG. 3, the poppet valve shown in position at the end of the production cycle;  
         [0032]    [0032]FIG. 6 is a detailed cross-sectional view of the poppet valve of FIG. 5 shown in position at the start of the unloading cycle;  
         [0033]    [0033]FIG. 7 is a detailed cross-sectional view of the poppet valve of FIG. 5 shown in position at the end of the unloading cycle;  
         [0034]    [0034]FIG. 8 is a schematic cross-sectional view of an alternate embodiment of the unloading valve of FIG. 3 showing an optional latching mechanism; and  
         [0035]    [0035]FIG. 9 is a schematic cross-sectional view of an optional plunger landing assembly, positioned at the uphole end of the unloading valve&#39;s valve stem. 
     
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT  
       [0036]    Having reference to FIGS. 1 a - 1   b , a plunger-actuated gas lift production system  10 , according to the present invention, is shown. The system typically comprises a tubing string  11  having a bore  12  and which extends downhole from a surface wellhead  13 . The tubing string  11  extends down a wellbore having a casing  14  and into a formation  15  containing a hydrocarbon reserve or reservoir  16 , under pressure.  
         [0037]    In a preferred embodiment of the invention, a conventional lubricator  17  and plunger  18 , common to conventional plunger-lift systems, are connected to the tubing string  11  at surface  19 . The plunger  18  is designed to free fall through the tubing string  11 , but is designed to have tolerances sufficiently tight to create a liquid seal when being lifted up the tubing string  11 . The plunger  18  is retained in the lubricator  17  by a catching mechanism  20  which is pneumatically controlled by the pressure in an annulus  21 .  
         [0038]    A conventional packer  22  is set in the wellbore between the casing  14  and the tubing string  11  above a plurality of perforations  23  in the casing  14  which define an isolated area above the packer  22  and to the surface  19 , referred to as the annulus  21 . Typically, the packer  22  is set as close above the perforations  23  as is possible.  
         [0039]    A conventional source of pressurized gas  24 , such as a compressor, provides a continuous slipstream of compressed gas into the isolated annulus  21  through a gas inlet port  26  at the wellhead  13 . One such compressor, suitable for pressurizing the annulus, is a small 5-15 HP conventional gas compressor package with a prime mover and shut down and safety controls.  
         [0040]    An unloading valve  100  is seated in a housing  101  in the bore  12  of the tubing string  11  uphole and adjacent to the packer  22  location. The unloading valve  100  is operable to shuttle between two positions, a first production position wherein formation fluids are allowed to flow to the surface  19  and a second lift position wherein production is temporarily blocked while accumulated liquids L, such as oil and water, are lifted to the surface  19 .  
         [0041]    In operation, as shown in FIG. 1 a , the isolated annulus  21  stores energy over time as a result of the influx of compressed gas  25 . In the production position the well continues to produce while the annulus  21  builds pressure without having to shut the well in.  
         [0042]    Having reference to FIG. 1 b , when the pressure in the annulus  21  reaches a predetermined threshold, a pneumatic controller  27  releases the plunger  18  from the lubricator  17 , causing it to fall down the bore  12  of the tubing string  11 , until it contacts the unloading valve  100 . The plunger  18  actuates the unloading valve  100  to the lift position, blocking production and opening an unloading port  102 , releasing the stored pressurized gas  25  in the annulus  21  to exit via the tubing string  11 . Any accumulated liquid L is carried up the tubing string  11  ahead of the plunger  18  and the released gas  25 , where it can be discharged at the surface  19 . The plunger  18  acts as a plug, lifting the liquids I which have accumulated ahead of it. When the plunger  18  reaches the lubricator  17  at the top of it&#39;s cycle, it is again retained in the lubricator  17  until the cycle begins again.  
         [0043]    Having reference to FIG. 2 a , one such conventional plunger design is shown. The plunger  18  comprises a cylindrical body  30 , typically formed of steel, having an exterior diameter smaller than the inside diameter of the tubing string  11  to allow free fall. The exterior of the cylindrical body  30  is fitted with annular spring loaded pads  31  designed to contact the inside of the tubing string  11  and to form a liquid seal therebetween. A top end  32  of the cylinder  30  is formed into a standard API “fish neck”  33  to allow the plunger  18  to be wireline retrievable, should it need to be recovered from the bottom of the tubing string  11 . The cylindrical body  30  has a central bore  34  drilled axially therethrough extending from a bottom end  35  of the cylinder  30  to the top end  32  to allow fluids to pass therethrough during fall. Optionally, a series of ports  36  may be added, branching from the central bore  34  to allow a more rapid fluid passage and thus a more rapid descent down the tubing string  11 . A rod-actuated shuttle valve (not detailed) is fitted within the cylinder bore  34  and is moveable between a first position wherein the bore  34  is open to the passage of fluids and a second position wherein the bore  34  is closed, by the valve, to the passage of fluids. In the first open position, the plunger  18  is able to fall freely through any accumulated liquid L. In the second closed position, the plunger  18  is operative to act as a plug to lift liquid L from the tubing string  11 .  
         [0044]    An actuator rod  37  is connected to the plunger valve and is axially movable within the plunger bore  34 . The rod  37  protrudes sufficiently outside the bore of the cylindrical body so as to allow impact with an obstruction within the lubricator  17  or downhole in the tubing string  11  to drive the rod  37  axially within the bore  34  to actuate the plunger valve between the open and closed positions, respectively. When the plunger valve is in the closed position, the rod  37  extends above the top of the fish neck  33  and when the plunger valve is in the open position, the rod  37  protrudes from the bottom  35  of the plunger  18 .  
         [0045]    As shown in FIG. 2 b , a bumper pad  40  in the lubricator  17  acts as the obstruction at the wellhead  13 , causing the actuator rod  37  to move downward within the plunger  18 , opening the plunger valve.  
         [0046]    The plunger catching device  20  is threadably connected to the lubricator  17  at a side port  41 . The catching device  20  comprises a spring-loaded steel pin  42 , extending into the lubricator  17  and having the extending end  43  cut at an angle which enables the pin  42  to retract briefly when struck by the arriving plunger  18  and then return, as a result of the spring-loaded action, into the lubricator  17  to prevent the plunger  18  from falling. The pneumatic controller valve  27  is actuated by a pressure switch P on the annulus  21  and acts to retract the pin  42 , releasing the plunger  18  when the pressure in the annulus  21  reaches a predetermined threshold.  
         [0047]    Having reference to FIG. 3 and in greater detail, the unloading valve  100  is positioned in the tubing string  11 , typically 2-3 meters above the packer and comprises the tubular housing  101 , threaded for connection to the tubing string  11 . The tubular housing  101  has an outer wall  103  and a bore  104 . The housing bore  103  is coaxial with the bore  12  of the tubing string  11  when the housing  101  is threaded into the tubing string  11 , permitting the flow of fluids from the reservoir  16  to the surface  19 . Upper and lower production ports  105 ,  106  are formed in the housing wall  103  and are connected to provide fluid communication therebetween in the production position.  
         [0048]    In a preferred embodiment of the invention, an outer tubular sleeve  107  is fitted around the housing  101 , extending above and below the production ports  105 , 106 , and is sealing engaged to an exterior surface  108  of the housing wall  103 , forming an annular bypass chamber  109  therebetween to fluidly connect the ports  105 , 106 . Production fluid flowing from the reservoir  16  can thus enter the bypass chamber  109  via the lower port  106 , flow up the bypass chamber  109 , bypassing a substantial portion of the unloading valve  100  and reentering the tubing string  11  through the valve&#39;s upper port  105  for communication and production to the surface  19 . Further, the unloading port  102  is formed through the outer sleeve  107  and the housing wall  103  to permit communication between the annulus  21  and the housing&#39;s bore  104 , operable during the lift position.  
         [0049]    The unloading valve  100  further comprises a valve stem  110  having an uphole piston  111  and a larger downhole piston  112 . The valve stem  110  is housed within the housing bore  104  positioned intermediate the upper  105  and lower  106  ports and is movable axially therein between an uphole position and a downhole position.  
         [0050]    In the production position, as shown in FIG. 3, the smaller uphole piston  111  is positioned to block the unloading port  102  ensuring there is no communication between the annulus  21  and the tubing string  11 . This allows pressure to build in the annulus  21 . The upper production port  105  remains open. The larger downhole piston  112  is positioned uphole so that the lower production port  106  is also open. As a result, with both production ports  105 , 106  open, fluids are able to bypass the unloading valve  100  and flow to the surface  19  at the same time annulus pressure is increasing, in preparation for an unloading cycle.  
         [0051]    Having reference to FIG. 4, in the lift position the downhole piston  112  is positioned downhole from the lower production port  106 , sealingly engaging the wall  103  of the housing  101  below production port  106 , blocking the flow of fluids from the reservoir  16  and into the housing&#39;s bore  104 , effectively stopping production. Simultaneously, the uphole piston  111  is positioned sufficiently downhole to open the unloading port  102 . High pressure gas  25 , stored in the annulus  21 , flows through the unloading port  102  and into the tubing string  11 , where it rapidly flows to the surface  19 , carrying the plunger  18  and any accumulated liquids L ahead of it.  
         [0052]    Having reference again to FIG. 4, the unloading valve  100  preferably further comprises a valve body  120  which supports the valve stem  110  within the housing  101 . An inner surface  121  of the housing  101  is profiled at one or more locations to form inwardly extending upward facing landing shoulders  122 , 123  to support the valve body  120 .  
         [0053]    The valve body  120  is a tubular body having a bore  124  and having an outer diameter sized to be freely movable within the housing&#39;s bore  104  for enabling wireline installation and retrieval to the housing  101 . An uphole end  125  of the valve body  120  is profiled with an outwardly extending downward facing shoulder  126  for engaging a landing shoulder  123  of the housing  101 , thus limiting the downward movement of the valve body  120  when run into the housing  101  using wireline and for positioning the valve body  120  in relation to the housing ports  102 ,  105 ,  106 . Preferably the uphole end  125  of the valve body  120  is inwardly tapered to guide a wireline retrieval tool. Optionally, an interior surface  127  of the valve body  120 , adjacent the uphole end  125 , is further profiled  128  to receive the wireline retrieval tool, to be used in the event that other structures used normally to retrieve the tool are damaged or lost during retrieval.  
         [0054]    An exterior surface  129  of the valve body  120  is profiled and fitted with upper and lower valve body seals  130 ,  131 , preferably a combination of polypak and pneumatic seals, to sealingly engage the valve body  120  against the inner wall of the housing  101 , between the production ports  105 , 106 . A series of radially extending ports  132  are formed about the circumference of and through the valve body  120  which correspond with the unloading port  102  in the housing  101 , thus completing fluid communication between the annulus  21  and the valve body  120 . These ports  131  are alternately closed and opened in the production and lift positions, respectively, by the movement of the upper piston  111 .  
         [0055]    The interior surface  127  of the valve body  120  is further profiled to accommodate the axially movable valve stem  110  which connects upper  111  and lower  112  pistons. An inwardly extending, downward facing shoulder  133  is formed in the bore  124  of the valve body  120  above the radially extending ports  132  against which the upper piston  111  stops when in the uphole position, limiting the valve stem&#39;s movement.  
         [0056]    An uphole end  134  of the valve stem  110  extends above the upper piston  111  beyond the uphole end  125  of the valve body  120  to act as a contact surface for the plunger  18 . The valve stem&#39;s uphole end  134  is sized so as to create an annulus  135  therebetween of sufficient size to allow unrestricted flow of gas  25  from the unloading port  102 . Further, the uphole end  134  is used as a “fishneck” for normal wireline retrieval.  
         [0057]    Again, having reference to FIG. 4, shown in the lift position, the valve stem  110  extends below a downhole end  136  of the valve body  120 . The larger downhole piston  112  is provided with seals  137  and is sized so as to sealingly engage the wall  103  of the housing  101 . Pressure in the reservoir  16  acts at the larger piston  112  face to move the valve stem  110  to the uphole production position when the pressure in the reservoir  16  is greater than the pressure in the annulus  21 .  
         [0058]    In summary, valve  100  in the production position, as shown in FIG. 3, begins a production cycle positioned so that the smaller uphole piston  111  blocks the unloading port  102  to allow the pressure to build in the annulus  21 , while simultaneously, the lower piston  12  is positioned to open the lower production port  106  and allow production fluids to bypass the unloading valve  100  and flow to the surface  19 .  
         [0059]    When moved to the lift position by the plunger  18 , to begin an unloading cycle as shown in FIG. 4, the uphole piston  111  is positioned downhole to open the unloading port  102 , allowing the gas  25  from the annulus  21  to enter the valve body  120  and the tubing string  11 , where it lifts the plunger and fluids (not shown) accumulated therein. Simultaneously, the downhole piston  112  is positioned to block the flow of fluids from the reservoir  16  and to act as a check valve, preventing high pressure gas  25  released from the annulus  21  leaking into and shocking the formation  15 . When the pressure in the annulus  21  has released, the reservoir pressure acts on the downhole piston  112  to move the valve  100  to the production position to repeat the production cycle once again.  
         [0060]    Optionally, as shown in FIG. 5, the valve stem  110  is fit with a gas poppet valve  150  adjacent a lower surface  151  of the uphole piston  111 , to advantageously use differential pressure to assist in the axial shifting movement of the valve stem. In the present embodiment, the poppet valve is used in combination with the plunger, and not independently to shift the valve stem. The poppet valve  150  is an annular sleeve fitted between the valve stem  110  and the valve body  120 . At the upper end of the poppet, inward shoulders  148  alternately engage a shoulder  149  formed on the valve stem  110 , limiting relative axial movement.  
         [0061]    The interior surface  127  of the valve body  120  is profiled with an inwardly extending downward facing shoulder  152  below the radially extending ports  132  and an inwardly extending upward facing shoulder  153  adjacent the bottom valve body seals  131  to guide and to limit the axial movement of the poppet valve  150 . Further, the interior wall  127  of the housing  101  is profiled to form an annular gallery  154  about the valve body  120  to communicate with the unloading port  102  connected to the well annulus  21 . A series of small ports  155  are formed in the valve body  120  adjacent the poppet valve  150  to provide fluid communication between the gallery  154  and the poppet valve  150 . The poppet valve  150  is fit with a larger lower piston  156  against which the pressure of the annulus gas  25  acts to assist the downhole axial movement of the valve stem  110 . The uphole piston  111  of the valve stem  110  can move independent of the poppet valve piston  156 . The poppet valve piston  156  is fit with seals  157  to sealingly engage the piston  156  against the valve body  120 . An upper spring  158  is housed between the uphole valve stem piston  111  and the poppet valve  150  and is supported at a lower end by a shoulder  159  formed at a top end  160  of the poppet valve  150 . A second larger spring  161  is housed between a bottom end  162  of the poppet valve  150  and the inwardly extending upward facing shoulder  153  of the valve body  120 , adjacent the bottom valve body seals  131 . The lower spring  161  biases the poppet valve  150  to an uphole position, compressing the upper spring  158  and assisting the valve stem  110  to remain in the uphole position blocking the unloading port  102  as pressure builds in the annulus  21 .  
         [0062]    As shown in FIGS.  5 - 7 , the operation of the poppet valve is a result of pressure changes in the annulus  21  relative to the pressure in the reservoir  16 . The poppet valve  150  acts to assist the valve stem  110  movement in both the lift position as a result of plunger  18  impact and in the production position as a result of differential pressure.  
         [0063]    At the end of a production cycle, as shown in FIG. 5, the pressure in the annulus  21  approaches a predetermined high pressure threshold. The pressure in the gallery  154  increases as a result of high pressure gas entering via the unloading port  102 . The gas  25  acts at an upper face  13  of the lower piston  156 , driving the piston downwardly, urging poppet shoulder  148  to engage shoulder  149  and preload the valve stem  110  downwardly.  
         [0064]    In the illustrated embodiment, the resulting preload on the poppet valve  150  is insufficient to actuate the valve stem  110 . In an alternate embodiment, the spring loads and differential pressures can be balanced to enable pressure differential operation on the poppet to operate the valve stem without the need for contact by the plunger.  
         [0065]    The valve stem  110  has not yet been contacted by the plunger  18  and therefore remains in the production position.  
         [0066]    As shown in FIG. 6, when the pressure in the annulus  21  reaches the threshold, the plunger (not shown) is released from the lubricator (not shown) and falls down the tubing string  11  to contact the uphole end  134  of the valve stem  110 . The valve stem  110  moves more readily to the lift position as a result of differential pressure on the poppet valve  150 . The upper spring  158  is caused to relax and the lower spring  161  to compress.  
         [0067]    Having reference to FIG. 7, when the pressure in the annulus  21  has been relieved, the pressure acting at the gallery ports  155  is no longer high enough to compress the lower spring  161 , which returns to its relaxed position. The poppet valve  150  moves freely upwardly which acts to compress the upper spring  158  upwardly, preloading the upper piston  111 . The pressure in the reservoir  16 , now larger than that in the annulus  21 , acts on the downhole piston  112  to move the valve stem  110  to the production position, once again.  
         [0068]    Optionally, as shown in FIG. 8, a valve body  200  of an alternate embodiment is retained into the housing  101  using an implementation of a conventional latching mechanism  201 . One such mechanism comprises a ring  202  formed about a lower exterior surface  203  of the valve body  200 , having a plurality of outwardly extending profiled dogs  204  which are designed to fit a plurality of corresponding profiles  205  in the housing&#39;s interior wall  206 . Outwardly extending inclined cam surfaces  207  attached to the valve body  200  below the dogs  204 , bias the dogs  204  outwardly into engagement with the housing&#39;s profiles  205 . The axially moveable cam surfaces  207  are connected to the valve body  200  using shear pins  208 . When the valve body  200  is retrieved from the housing  101  using wireline, upward pull on the valve body  200  shears pins  208 , allowing the inclined cams  207  to fall to a downhole position, enabling the dogs  204  to move inward and release from the housing  101 . The valve body  200  can then be retrieved to the surface  19 . FIG. 8 also serves to illustrate another embodiment of the valve having a valve stem  110  and ports  102 , 105 , 106 .  
         [0069]    Having reference to FIGS. 8 and 9 and in another embodiment of the invention, the upper end  134  of the valve stem  110  is fitted with a plunger landing assembly  200  to protect the valve stem  110  from excessive, potentially damaging force exerted by a falling plunger. The plunger landing assembly  300  comprises an outer spring  301  and an inner spring  302 . The outer spring  301  is of sufficient size and material strength to withstand the entire force exerted by the falling plunger. The inner spring  302  has an outer diameter such that the inner spring  302  fits freely inside the outer spring  301 , and is of sufficient length so that, when the plunger landing assembly  300  is mounted to the top  134  of the valve stem  110 , the inner spring  302  is operative to contact with the top  134  of the valve stem  110  when the landing assembly  300  is struck, compressing the outer spring  301 . The outer spring  301  is fitted with upper  303  and lower  304  spring retainers.  
         [0070]    In the implementation shown in FIG. 9, the upper retainer  303  is a cap having a downward facing internal chamber  305  to which the top flight  306  of the inner spring  302  is attached. The lower spring retainer  304  is an annular ring attached to a bottom flight  307  of the outer spring  301  and having a bore  308  through which the inner spring  302  can move axially therethrough. A circular steel plate  309  is attached to a bottom flight  310  of the inner spring  302  so as to contact the top  134  of the valve stem  110  and transfer the downwardly moving force imparted by the plunger  18 . The annular ring  304  at the bottom of the outer spring  301  is profiled at a lower surface  311  to correspond to the angled upward facing end  125  of the valve body  120 .  
         [0071]    Optionally, as shown in FIG. 8, a standard API fish neck  312  may be attached to the top of the landing assembly  300  to allow the landing assembly  300  to be wireline conveyed into and retrieved from the tubing string  11 .  
         [0072]    In operation, the falling plunger  18  strikes the top of the landing assembly  300  causing the outer spring  301  to compress and transfer a portion of the downward moving force to the valve housing  101 . The remainder of the force is transferred to the valve stem  110  by the inner spring  302 . This transferred force is sufficient to move the valve stem  110  axially to the lift position.  
         [0073]    In another option, rather that a plunger actuation, the valve  150  may be operated using remote actuation or electrical operation of the valve.