Abstract:
A system and method for lifting reservoir fluids from reservoir to surface through a wellbore having a first tubing string extending through a packer in a wellbore casing. The system includes a bi-flow connector in the first tubing string, a second tubing string in the first tubing string below the bi-flow connector, and a third tubing string in the first tubing string above and connected with the bi-flow connector. A fluid displacement device in the third tubing string is configured to move reservoir fluids to the surface. The first tubing string allows pressured gas to move from the surface through the bi-flow connector to commingle with and lift reservoir fluids through annuli defined by the first and second tubing strings and defined by the casing and the first tubing string. The bi-flow connector is configured to allow simultaneous and non-contacting flow of the downward pressured gas and lifted reservoir fluid.

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application is a continuation-in-part of co-pending U.S. application Ser. No. 12/001,152 filed on Dec. 10, 2007, which application is hereby incorporated by reference for all purposes in its entirety. 
    
    
     STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT 
     N/A 
     REFERENCE TO MICROFICHE APPENDIX 
     N/A 
     BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     This invention relates to production systems and methods deployed in subterranean oil and gas wells. 
     2. Description of the Related Art 
     Many oil and gas wells will experience liquid loading at some point in their productive lives due to the reservoir&#39;s inability to provide sufficient energy to carry wellbore liquids to the surface. The liquids that accumulate in the wellbore may cause the well to cease flowing or flow at a reduced rate. To increase or re-establish the production, operators place the well on artificial lift, which is defined as a method of removing wellbore liquids to the surface by applying a form of energy into the wellbore. Currently, the most common artificial lift systems in the oil and gas&#39; industry are down-hole pumping systems, plunger lift systems, and compressed gas systems. 
     The most popular form of down-hole pump is the sucker rod pump. It comprises a dual ball and seat assembly, and a pump barrel containing a plunger. A string of sucker rods connects the downhole pump to a pump jack at the surface. The pump jack at the surface provides the reciprocating motion to the rods which in turn provides the reciprocal motion to stroke the pump, which is a fluid displacement device. As the pump strokes, fluids above the pump are gravity fed into the pump chamber and are then pumped up the production tubing and out of the wellbore to the surface facilities. Other downhole pump systems include progressive cavity, jet, electric submersible pumps and others. 
     A plunger lift system utilizes compressed gas to lift a free piston traveling from the bottom of the tubing in the wellbore to the surface. Most plunger lift systems utilize the energy from a reservoir by closing in the well periodically in order to build up pressure in the wellbore. The well is then opened rapidly which creates a pressure differential, and as the plunger travels to the surface, it lifts reservoir liquids that have accumulated above the plunger. Like the pump, the plunger is also a fluid displacement device. 
     Compressed gas systems can be either continuous or intermittent. As their names imply, continuous systems continuously inject gas into the wellbore and intermittent systems inject gas intermittently. In both systems, compressed gas flows into the casing-tubing annulus of the well and travels down the wellbore to a gas lift valve contained in the tubing string. If the gas pressure in the casing-tubing annulus is sufficiently high compared to the pressure inside the tubing adjacent to the valve, the gas lift valve will be in the open position which subsequently allows gas in the casing-tubing annulus to enter the tubing and thus lift liquids in the tubing out of the wellbore. Continuous gas lift systems work effectively unless the reservoir has a depletion or partial depletion drive, which results in a pressure decline in the reservoir as fluids are removed. When the reservoir pressure depletes to a point that the gas lift pressure causes significant back pressure on the reservoir, continuous gas lift systems become inefficient and the flow rate from the well is reduced until it is uneconomic to operate the system. Intermittent gas lift systems apply this back pressure intermittently and therefore can operate economically for longer periods of time than continuous systems. Intermittent systems are not as common as continuous systems because of the difficulties and expense of operating surface equipment on an intermittent basis. 
     Horizontal drilling was developed to access irregular fossil energy deposits in order to enhance the recovery of hydrocarbons. Directional drilling was developed to access fossil energy deposits some distance from the surface location of the wellbore. Generally, both of these drilling methods begin with a vertical hole or well. At a certain point in this vertical well, a turn of the drilling tool is initiated which eventually brings the drilling tool into a deviated position with respect to the vertical position. 
     It is not practical to install most artificial lift systems in the deviated sections of directional or horizontal wells or deep into the perforated section of vertical wells since down-hole equipment installed in these regions may be inefficient or can undergo high maintenance costs due to wear and/or solids and gas entrained in the liquids interfering with the operation of the pump. Therefore, most operators only install down-hole artificial lift equipment in the vertical portion of the wellbore above the reservoir. In many vertical wells with relatively long perforated intervals, many operators choose to not install artificial lift equipment in the well due to the factors above. Downhole pump systems, plunger lift systems, and compressed gas lift systems are not designed to recover any liquids that exist below the downhole equipment. Therefore, in many vertical, directional, and horizontal wells, a column of liquid ranging from hundreds to many thousands of feet may exist below the down-hole artificial lift equipment. Because of the limitations with current artificial lift systems, considerable hydrocarbon reserves cannot be recovered using conventional methods in depletion or partial depletion drive directional or horizontally drilled wells, and vertical wells with relatively long perforated intervals. Thus, a major problem with the current technology is that reservoir liquids located below conventional down-hole artificial lift equipment cannot be lifted. 
     There is a need to provide an artificial lift system that will enable the recovery of liquids in the deviated sections of directional or horizontal wellbores, and in vertical wells with relatively long perforated intervals. 
     There is a need to provide an artificial lift system that will enable the recovery of liquids in vertical wells with relatively long perforated intervals and in the deviated sections of directional and horizontal wellbores with smaller casing diameters. 
     There is a need to lower the artificial lift point in vertical wells with relatively long perforated intervals and in wells with deviated or horizontal sections. 
     There is a need to provide a high velocity volume of injection gas to more efficiently sweep the reservoir liquids from the wellbore. 
     There is a need to provide a more efficient, less costly wellbore liquid removal process. 
     There is a need for a less costly artificial lift method for vertical wells with relatively long perforated intervals and for wells with deviated or horizontal sections. 
     There is a need for a less costly and more efficient artificial lift method for wells that still have sufficient reservoir energy and reservoir gas to lift liquids from below to above the downhole artificial lift equipment. 
     Finally, there is a need to provide a more efficient gas and solid separation method to lower the lift point in wells with deviated and horizontal sections and for vertical wells with relatively long perforated intervals. 
     BRIEF SUMMARY OF THE INVENTION 
     A gas assisted downhole system is disclosed, which is an artificial lift system designed to recover by-passed hydrocarbons in directional, vertical and horizontal wellbores by incorporating a dual tubing arrangement. In one embodiment, a first tubing string contains a gas lift system, and a second tubing string contains a downhole pumping system. In the first tubing string, the gas lift system, which is preferably intermittent, is utilized to lift reservoir fluids from below the downhole pump to above a packer assembly where the fluids become trapped. As more reservoir fluids are added above the packer, the fluid level rises in the casing annulus above the downhole pump installed in the adjacent second tubing string, and the trapped reservoir fluids are pumped to the surface by the downhole pump. In another embodiment, the second tubing string contains a downhole plunger system. As reservoir fluids are added above the packer, the fluid level rises in the casing annulus above the downhole plunger installed in the adjacent second tubing string, and the trapped reservoir fluids are lifted to the surface by the downhole plunger system. 
     A dual string anchor may be disposed with the first tubing string to limit the movement of the second tubing string. The second tubing string may be removably attached with the dual string anchor with an on-off tool without disturbing the first tubing string. A one-way valve may also be used to allow reservoir fluids to flow into the first tubing string in one direction only. The one way valve may be placed in the first tubing string below the packer to allow trapped pressure below the packer to be released into the first tubing string. The valve provides a pathway to the surface for the gas trapped below the packer. The resulting reduced back pressure on the reservoir may lead to production increases. 
     In another embodiment, the second tubing string may be within the first tubing string, and the injected gas may travel down the annulus between the first and second tubing strings. The second string may house a fluid displacement device, such as a downhole pumping system or a plunger lift system. A bi-flow connector may anchor the second string to the first string and allow reservoir liquids in the casing tubing annulus to pass through the anchor to the downhole pump. In one embodiment, the bi-flow connector may be a cylindrical body having a thickness, a first end, a second end, a central bore from the first end to said second end, and a side surface. A first channel may be disposed through the thickness from the first end to the second end. A second channel may be disposed through the thickness from the side surface to the central bore, with the first channel and second channel not intersecting. Injected gas may be allowed to pass vertically through the bi-flow connector to lift liquids from below the downhole pump to above the downhole pump. The bi-flow connector prevents the injected gas from contacting the reservoir liquids flowing through the bi-flow connector. Also contemplated are multiple channels in addition to the first channel and multiple channels in addition to the second channel. 
     In yet another embodiment, gas from the reservoir lifts reservoir liquids from below the fluid displacement device, such as a downhole pump or a plunger, to above the fluid displacement device. A first tubing string may contain the fluid displacement device above a packer assembly. A blank sub may be positioned between an upper perforated sub and a lower perforated sub in the first tubing string below the fluid displacement device. A second tubing string within the first tubing string and located below the lower perforated sub may lifts liquids using the gas from the reservoir. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       For a further understanding of the nature and objects of the present invention, reference is had to the following figures in which like parts are given like reference numerals and wherein: 
         FIG. 1  depicts a directional or horizontal wellbore installed with a conventional rod pumping system of the prior art. 
         FIG. 2  depicts a conventional gas lift system in a directional or horizontal wellbore of the prior art. 
         FIG. 3  depicts an embodiment of the invention utilizing a rod pump and a gas lift system. 
         FIG. 4  depicts another embodiment of the invention similar to  FIG. 3  except with no internal gas lift valve. 
         FIG. 5  depicts yet another embodiment of the invention having a Y block. 
         FIG. 6  depicts another embodiment of the invention similar to  FIG. 5  except with no internal gas lift valve. 
         FIG. 7  depicts another embodiment similar to  FIG. 3 , except with a dual string anchor and an on-off tool. 
         FIG. 8  depicts another embodiment similar to  FIG. 7 , except with no internal gas lift valve. 
         FIG. 9  depicts another embodiment similar to  FIG. 7 , except with a one-way valve. 
         FIG. 10  is the embodiment of  FIG. 9 , except shown in a completely vertical wellbore. 
         FIG. 11  is an embodiment similar to  FIG. 11 , except that an alternative embodiment plunger lift system is installed in place of the downhole pump system, and with no surface tank and no dual string anchor. 
         FIG. 12  depicts another embodiment in a vertical wellbore utilizing a bi-flow connector. 
         FIG. 13  is the embodiment of  FIG. 12  except in a horizontal wellbore. 
         FIG. 13A  is an isometric view of a bi-flow connector. 
         FIG. 13B  is a section view along line  13 A- 13 A of  FIG. 13 . 
         FIG. 13C  is a top view of  FIG. 13A . 
         FIG. 13D  is a section view similar to  FIG. 13B  except with the bi-flow connector threadably attached at a first end with a first tubular and at a second end with a second tubular. 
         FIG. 14  is the embodiment of  FIG. 13  except that an alternative embodiment plunger lift system is installed in place of the downhole pump system. 
         FIG. 15  depicts another embodiment that utilizes gas that emanates from the reservoir to lift liquids from the curved or horizontal section of the wellbore. 
         FIG. 16  is the embodiment of  FIG. 15  except it is shown in a vertical wellbore. 
         FIG. 17  is the embodiment of  FIG. 16  except that an alternative embodiment plunger lift system is installed in place of the downhole pump system. 
     
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
       FIG. 1  shows one example of a conventional rod pump system of the prior art in a directional or horizontal wellbore. As set out in  FIG. 1 , tubing  1 , which contains pumped liquids  13  is mounted inside a casing  6 . A pump  5  is connected at the end of tubing  1  in a seating nipple  48  nearest the reservoir  9 . Sucker rods  11  are connected from the top of pump  5  and continue vertically to the surface  12 . Casing  6 , cylindrical in shape, surrounds and may be coaxial with tubing  1  and extends below tubing  1  and pump  5  on one end and extends vertically to surface  12  on the other end. Below casing  6  is curve  8  and lateral  10  which is drilled through reservoir  9 . 
     The process is as follows: reservoir fluids  7  are produced from reservoir  9  and enter lateral  10 , rise up curve  8  and casing  6 . Because reservoir fluids  7  are usually multiphase, they separate into annular gas  4  and liquids  17 . Annular gas  4  separates from reservoir fluids  7  and rises in annulus  2 , which is the void space formed between tubing  1  and casing  6 . The annular gas  4  continues to rise up annulus  2  and then flows out of the well to the surface  12 . Liquids  17  enter pump  5  by the force of gravity from the weight of liquids  17  above pump  5  and enter pump  5  to become pumped liquids  13  which travel up tubing  1  to the surface  12 . Pump  5  is not considered to be limiting, but may be any down-hole pump or pumping system, such as a progressive cavity, jet pump, or electric submersible, and the like. 
       FIG. 2  shows one example of a conventional gas lift system of the prior art in a directional or horizontal wellbore. Referring to  FIG. 2 , inside the casing  6 , is tubing  1  connected to packer  14  and conventional gas lift valve  22 . Below casing  6  is curve  8  and lateral  10  which is drilled through reservoir  9 . The process is as follows: reservoir fluids  7  from reservoir  9  enter lateral  10  and rise up curve  8  and casing  6  and enter tubing  1 . The packer  14  provides pressure isolation which allows annulus  2 , which is formed by the void space between casing  6  and tubing  1 , to increase in pressure from the injection of injection gas  16 . Once the pressure increases sufficiently in annulus  2 , conventional gas lift valve  22  opens and allows injection gas  16  to pass from annulus  2  into tubing  1 , which then commingles with reservoir fluids  7  to become commingled fluids  18 . This lightens the fluid column and commingled fluids  18  rise up tubing  1  and then flow out of the well to surface  12 . 
       FIG. 3  shows an embodiment utilizing a downhole pump and a gas lift system in a horizontal or deviated wellbore. Referring to  FIG. 3 , inside casing  6 , is tubing  1  which begins at surface  12  and contains internal gas lift valve  15 , bushing  25 , and inner tubing  21 . Inner tubing  21  may be within tubing  1 , such as concentric. Bushing  25  may be a section of pipe whose purpose is to threadingly connect pipe joints using both its outer diameter and its inner diameter. Bushing  25  may have pipe threads at one or both ends of its outer diameter, and pipe threads at one or both ends of its inner diameter. Other types of bushings and connection means are also contemplated. Tubing  1  is sealingly engaged to packer  14 . Tubing  1  and inner tubing  21  extend below packer  14  through curve  8  and into lateral  10 , which is drilled through reservoir  9 . Inside casing  6  and adjacent to tubing  1  is tubing  3 , which contains sucker rods  11  connected to pump  5 . Pump  5  is connected to the end of tubing  3  by seating nipple  48 . Tubing  3  is not sealingly engaged to packer  14 . 
     The process may be as follows: reservoir fluids  7  enter lateral  10  and enter tubing  1 . The reservoir fluids  7  are commingled with injection gas  16  to become commingled fluids  18  which rise up chamber annulus  19 , which is the void space formed between inner tubing  21  and tubing  1 . The commingled fluids  18  then exit through the holes in perforated sub  24 . Commingled gas  41  separates from commingled fluids  18  and rises in annulus  2 , which is formed by the void space between casing  6  and tubing  1  and tubing  3 . Commingled gas  41  then enters flow line  30  at the surface  12  and enters compressor  38  to become compressed gas  33 , and travels through flow line  31  to surface tank  34 . The compressor  38  is not considered to be limiting, in that it is not crucial to the design if another source of pressured gas is available, such as pressured gas from a pipeline. 
     Compressed gas  33  then travels through flow line  32  which is connected to actuated valve  35 . This actuated valve  35  opens and closes depending on either time or pressure realized in surface tank  34 . When actuated, valve  35  opens, compressed gas  33  flows through actuated valve  35  and travels through flow line  32  and into tubing  1  to become injection gas  16 . The injection gas  16  travels down tubing  1  to internal gas lift valve  15 , which is normally closed thereby preventing the flow of injection gas  16  down tubing  1 . A sufficiently high pressure in tubing  1  above internal gas lift valve  15  opens internal gas lift valve  15  and allows the passage of injection gas  16  through internal gas lift valve  15 . The injection gas  16  then enters the inner tubing  21 , and eventually commingles with reservoir fluids  7  to become commingled fluids  18 , and the process begins again. Liquids  17  and commingled gas  41  separate from the commingled fluids  18  and liquids  17  fall in annulus  2  and are trapped above packer  14 . Commingled gas  41  rises up annulus  2  as previously described. As more liquids  17  are added to annulus  2 , liquids  17  rise above and are gravity fed into pump  5  to become pumped liquids  13  which travel up tubing  3  to surface  12 . 
       FIG. 4  shows an alternate embodiment similar to the design in  FIG. 3  except that it does not utilize the internal gas lift valve  15 . 
       FIG. 5  shows yet another alternate embodiment utilizing a downhole pump and a gas lift system in a horizontal or deviated wellbore with a different downhole configuration from  FIG. 3 . Referring to  FIG. 5 , inside the casing  6  is tubing  1  which contains an internal gas lift valve  15  and is sealingly engaged to packer  14 . Packer  14  is preferably a dual packer assembly and is connected to Y block  50  which in turn is connected to chamber outer tubing  55 . Chamber outer tubing  55  continues below casing  6  through curve  8  and into lateral  10  which is drilled through reservoir  9 . Inner tubing  21  is secured by chamber bushing  22  to one of the tubular members of Y Block  50  leading to lower tubing section  37 . Inner tubing  21  may be concentric with chamber outer tubing  55 . The inner tubing  21  extends inside of Y block  50  and chamber outer tubing  55  through the curve  8  and into the lateral  10 . The second tubing string arrangement comprises a lower section  37  and an upper section  36 . The lower section  37  comprises a perforated sub  24  connected above a one way valve  28  and is then sealingly engaged in the packer  14 . 
     Perforated sub  24  is closed at its upper end and is connected to the upper tubing section  36 . Upper tubing section  36  comprises a gas shroud  58 , a perforated inner tubular member  57 , a cross over sub  59  and tubing  3  which contains pump  5  and sucker rods  11 . The gas shroud  58  is tubular in shape and is closed at its lower end and open at its upper end. It surrounds perforated inner tubular member  57 , which extends above gas shroud  58  to crossover sub  59  and connects to the tubing  3 , which continues to the surface  12 . Above the crossover sub  59 , and contained inside of tubing  3  at its lower end, is pump  5  which is connected to sucker rods  11 , which continue to the surface  12 . Annular gas  4  travels up annulus  2  into flowline  30  which is connected to compressor  38  which compresses annular gas  4  to become compressed gas  33 . The compressor  38  is not considered to be limiting, in that it is not crucial to the design if another source of pressured gas is available, such as pressured gas from a pipeline. 
     Compressed gas  33  flows through flowline  31  to surface tank  34  which is connected to a second flowline  32  that is connected to actuated valve  35 . This actuated valve  35  opens and closes depending on either time or pressure realized in surface tank  34 . When actuated valve  35  opens, compressed gas  33  flows through actuated valve  35  and travels through flowline  32  and into tubing  1  to become injection gas  16 . The injection gas  16  travels down tubing  1  to internal gas lift valve  15 , which is normally closed thereby preventing the flow of injection gas  16  down tubing  1 . A sufficiently high pressure in tubing  1  above internal gas lift valve  15  opens internal gas lift valve  15  and allows the passage of injection gas  16  through internal gas lift valve  15 , through Y Block  50  and into chamber annulus  19 , which is the void space between inner concentric tubing  21  and chamber outer tubing  55 . Injection gas  16  is forced to flow down chamber annulus  19  since its upper end is isolated by chamber bushing  25 . Injection gas  16  displaces the reservoir fluids  7  to become commingled fluids  18  which travel up the inner concentric tubing  21 . 
     Commingled fluids  18  travel out of inner concentric tubing  21  into one of the tubular members of Y Block  50 , through packer  14  and standing valve  28 , and then through the perforated sub  24  into annulus  2 , where the gas separates and rises to become annular gas  4  to continue the cycle. The liquids  17  separate from the commingled fluids  18  and fall by the force of gravity and are trapped in annulus  2  above packer  14  and are prevented from flowing back into perforated sub  24  because of standing valve  28 . As liquids  17  accumulate in annulus  2 , they rise above pump  5  and are forced by gravity to enter inside of gas shroud  58  and into perforated tubular member  57  where they travel up cross-over sub  59  to enter pump  5  where they become pumped liquids  13  and are pumped up tubing  3  to the surface  12 . 
       FIG. 6  shows an alternate embodiment of the invention similar to the design in  FIG. 5  except that it does not utilize the internal gas lift valve  15 . 
       FIG. 7  shows an alternate embodiment similar to  FIG. 3 , except that there is a downhole anchor assembly or dual string anchor  20  disposed with first tubing string  1  and installed and attached with second tubing string with on-off tool  26 . Referring to  FIG. 7 , first tubing string  1  is inside casing  6 . First tubing string  1  begins at the surface  12  and contains internal gas lift valve  15 , bushing  25 , perforated sub  24 , and inner tubing  21 . Perforated sub  24  is available from Weatherford International of Houston, Tex., among others. Tubing  1  is engaged to dual string anchor  20  and continues through it and is engaged to packer  14  and extends through it. Inner tubing  21  connects to bushing  25  and continues through perforated sub  24 , dual string anchor  20 , packer  14  and terminates prior to the end of tubing  1 . Dual string anchor  20  is available from Kline Oil Tools of Tulsa, Okla., among others. Other types of dual string anchors  20  are also contemplated. Inner tubing  21  may be within tubing  1 . Tubing  1  extends through and below dual string anchor  20  and through and below packer  14  through curve  8  and into lateral  10 , which is drilled through reservoir  9 . Second tubing string  3  is inside casing  6  and adjacent to first tubing string  1 . Second tubing string  3  contains perforated sub  23 , sucker rods  11 , pump  5 , seating nipple  48 , and on-off tool  26 . Second tubing string  3  may be selectively engaged to dual string anchor  20  with on-off tool  26 . On-off tool  26  is available from D&amp;L Oil Tools of Tulsa, Okla. and from Weatherford International of Houston, Tex., among others. Other types of on-off tool  26  and attachment means are also contemplated. On-off tool  26  may be disposed with perforated sub  23 , which may be attached with second tubing string  3 . 
     The process for  FIG. 7  is similar to that for  FIG. 3 . The dual string anchor  20  functions to immobilize the second tubing string  3  by supporting it with first tubing string  1 . Immobilization is important, since in deeper pump applications, the mechanical pump  5  may induce movement to second tubing string  3  which may in turn cause we on the tubulars. Movement may also cause the mechanical pump operation to cease or become inefficient. On-off tool  26  allows the second tubing string  3  to be selectively connected or disconnected from the dual string anchor  20  without disturbing the first tubing string  1 . The dual string anchor  20  minimizes inefficiencies in the pump and costly workovers to repair wear on the tubing strings. This movement is caused by the movement induced upon the second tubing string by the downhole pumping system. 
       FIG. 8  shows another alternate embodiment similar to the design in  FIG. 7  except that it does not utilize internal gas lift valve  15 . 
       FIG. 9  shows another alternate embodiment similar to the design of  FIG. 7 , except that  FIG. 9  includes one-way valve  28  disposed on first tubing string  1  below packer  14 . Referring to  FIG. 9 , when pressure conditions are favorable, one-way valve  28  opens to allow reservoir gas  27  to pass into chamber annulus  19 . One-way valve  28  may be a reverse flow check valve available from Weatherford International of Houston, Tex., among others. Other types of one-way valves  28  are also contemplated. Although only one one-valve  28  is shown, it is contemplated that there may be more than one one-way valve  28  for all embodiments. One-way valve  28  may be threadingly disposed with a carrier such as a conventional tubing retrievable mandrel or a gas lift mandrel. Other connection types, carriers, and mandrels are also contemplated. 
     One-way valve  28  functions to allow fluids to flow from outside to inside the device in one direction only. In  FIGS. 9-14 , one-way valve  28  may be placed in the first tubing string  1  below the packer  14  to vent trapped pressure below the packer  14  into the first tubing string  1 . In a vertical well application, this venting may assist the optimum functioning of the artificial lift system. One-way valve  28  has at least two functions: (1) it provides a pathway to the surface for reservoir gas  27  trapped below packer  14 , and (2) it leads to production increases by reducing back pressure on the reservoir. As can now be understood, one-way valve  28  may be positioned at a location on first tubing string  1 , such as below packer  14 , that is different than the location where injected gas  16  initially commingles with the reservoir fluids where inner tubing  21  ends. Injected gas  16  may initially commingle with reservoir fluids  7  at a first location, and one-way valve  28  may be disposed on first tubing string  1  at a second location. One-way valve  28  may be disposed above reservoir  9 , although other locations are contemplated. One-way valve  28  allows the venting of trapped fluids, and allows flow in only one direction. 
       FIG. 10  shows the embodiment of  FIG. 9  in a completely vertical wellbore. 
     As can now be understood, dual string anchor or dual tubing anchor  20  with on-off tool  26  and one way-valve  28  may be used independently, together, or not at all. For all embodiments in deviated, horizontal, or vertical wellbore applications, there may be (1) gas lift valve  15 , dual string anchor  20 , and one-way valve  28  below packer  14 , (2) no gas lift valve  15 , no dual string anchor  20 , and no one-way valve  28  below packer  14 , or (3) any combination or permutation of the above. Surface tank  34  and actuated valve  35  are also optional in all the embodiments. 
       FIG. 11  is an embodiment similar to  FIG. 10  in which pump  5  and sucker rods  11  have been replaced with an alternative embodiment plunger lift system, and there is no surface tank  34  and no one-way valve  28 . Referring to  FIG. 11 , the process is as follows. Initially, actuated valve  37  is open at surface  12 , which allows flow from tubing  3  to surface  12 . Actuated valve  35  is open and actuated valve  36  is closed. Supply gas  46 , which may emanate from the well or a pipeline, is compressed by compressor  38  and compressed gas  33  flows through flow line  31 , through actuated valve  35  and flow line  32 , and into tubing  1  to become injection gas  16 , which then flows down tubing  1 , through gas lift valve  15 , and through inner tubing  21 . At the end of inner tubing  21 , injection gas  16  combines with reservoir fluids  7  to become commingled fluids  18 , which rise up chamber annulus  19  and flow through perforated sub  24  into annulus  2 . Liquids  17  fall to the bottom of annulus  2 . 
     As more liquids are added in annulus  2 , they eventually rise above plunger  5  and into tubing  3  and rise above perforated sub  24 , which may cause the injection pressure to rise which signals actuated valve  35  to close, actuated valve  39  to open, and actuated valve  37  to close. Compressed gas  33  then flows through actuated valve  36  and through flow line  30 , and into annulus  2  to become injection gas  16 . When a sufficient volume of injection gas  16  has been added to annulus  2 , the pressure in annulus  2  rises sufficiently to signal actuated valve  37  to open, actuated valve  36  to close, and actuated valve  35  to open. The pressure differential lifts plunger  45  off of seating nipple  48  and rises up tubing  3  and pushes liquids  17  to surface  12 . Some injection gas  16  also flows to surface  12  via tubing  3 . Once the pressure on tubing  3  drops sufficiently, plunger  45  falls back down to seating nipple  48  and the process begins again. Other sequences of the timing of the opening and closing of the actuated valves are contemplated. Surface tank  34  may also be utilized. 
       FIG. 12  is another embodiment and utilizes an outer and inner tubing arrangement, such as concentric, incorporating a novel bi-flow connector  43  in a vertical wellbore. The bi-flow connector  43  is shown in detail in  FIGS. 13A-13D  and discussed in detail below.  FIG. 13  is similar to  FIG. 12  except in a horizontal wellbore. Although  FIG. 13  is discussed below, the discussion applies equally to  FIG. 12 . In  FIG. 13 , first tubing string  1  begins at surface  12  and is installed inside casing  6 , contains bi-flow connector  43 , bushing  25 , one way valve  29 , and is sealingly engaged to packer  14 . Mud anchor  40  may be connected to bi-flow connector  43  to act as a reservoir for particulates that fall out of liquids  17 , and to isolate the injection gas  16  from liquids  17 . Mud anchor  40  is a tubing with one end closed and one end open, and is available from Weatherford International of Houston, Tex., among others. First tubing string  1  continues below packer  14  and contains one way valve  28  and continues until it terminates in curve  8  or lateral  10 , or for  FIG. 12  in or below reservoir  9 . Within first tubing string  1  is second tubing string  21 , which is also sealingly engaged to bushing  25  and continues down through packer  14  and may terminate prior to the end of first tubing string  1 . Third tubing string  3  is within first tubing string, and begins at surface  12  and terminates in on-off tool  26 . On-off tool  26  allows third tubing string  3  to be selectively engaged to first tubing string  1 . On-off tool  26  is sealingly engaged to bi-flow connector  43 . Contained inside first tubing string  3  are sucker rods  11 , pump  5  and seating nipple  48 . Sucker rods  11  are connected to pump  5  which is selectively engaged into seating nipple  48 . Seating nipple  48  is available from Weatherford International of Houston, Tex., among others. 
     As shown in  FIGS. 13A-13D , bi-flow connector  43  is a cylindrically shaped body with a central bore  112  extending from a first end  105  to a second end  107  and having a thickness  109 . Vertical or first channels  102  pass through the thickness  109  of the bi-flow connector  43  from the first end  105  to the second end  107 . Horizontal or second channels  100  pass from the side surface  111  through the thickness  109  of the bi-flow connector  43  to the central bore  112 . Although shown vertical and horizontal, it is also contemplated that first channels may not be vertical and second channels may not be horizontal. Different numbers and orientations of channels are contemplated. The first channels  102  and second channels  100  do not intersect. Threads  104 ,  108  are on the side surface  111  of the bi-flow connector  43  adjacent its first and second ends  105 ,  107 . There may also be inner threads  106 ,  110  on the inner surface of the central bore  112  adjacent the first and second ends. As shown in  FIGS. 12-13 , the mud anchor  40  is attached with the inner threads  110 , and the first tubing string  1  is attached with the outer threads  104 ,  108 . In  FIG. 13D , the threaded connection between the bi-flow connector  43  between upper tubular  114  and lower tubular  116  is similar to the connection in  FIG. 13  between the bi-flow connector  43  and first tubing string  1 . 
     Returning to  FIG. 13 , the process may be as follows. Injection gas  16  travels down annulus  47  and passes vertically through bi-flow connector  43  and continues down through bushing  25 , packer  14 , second tubing string  21  and out into first tubing string  1  where it commingles with reservoir fluids  7  to become commingled fluids  18 . Reservoir gas emanates from reservoir  9  and may travel through one way valve  28  and become part of commingled fluids  18 , which rise up annulus  19  and travel through one way valve  29  and then separate into liquids  17  and commingled gas  41 . Liquids  17  may enter horizontally through bi-flow connector  43  and up to pump  5  where they become pumped liquids  13  and are pumped to surface  12 . Commingled gas  41  rises up annulus  2  to surface  12 . 
     As can now be understood, the bi-flow connector  43  allows downward injection gas to pass vertically through the tool, while simultaneously allowing reservoir liquids to pass horizontally through the tool, without commingling the reservoir liquids with the downwardly flowing injection gas. The bi-flow connector  43  also allows the inner tubing string, such as third tubing string  3 , to be selectively engaged to the outer tubing string, such as first tubing string  1 . The bi-flow connector  43  may be used in small casing diameter wellbores in which the installation of two side by side or adjacent tubing strings is impractical or impossible. The bi-flow connector  43  is advantageous to wells that have a smaller diameter casing. Other non-concentric tubing arrangement embodiments may require larger casing sizes. A plunger system is also contemplated in place of the downhole pump. 
       FIG. 14  is the same embodiment as  FIG. 13  except that an alternative embodiment plunger lift system is installed in place of the downhole pump system. A pump and a plunger are both fluid displacement devices. 
       FIG. 15  is another embodiment using only reservoir gas to lift the reservoir liquids from below the downhole pump to above the downhole pump. This embodiment is similar to  FIG. 13 , but no inner tubing, such as third tubing string  3 , is needed to house the downhole pump and no external injection gas is needed. It may also incorporate a one way valve  28  in the tubing string to prevent wellbore liquids from falling back down the wellbore. The one way valve  28  allows the liquids to be trapped above the packer until the pump can lift them to the surface. The smaller diameter of the inner tubing efficiently lifts reservoir fluids by forcing the reservoir gas into a smaller cross-sectional area whereby the gas is not allowed to rise faster than the reservoir liquids. Due to the smaller tubing size, a relatively small amount of reservoir gas can lift reservoir liquids the relatively short distance from the end of the tubing to the one way valve. 
     Referring to  FIG. 15 , first tubing string  1  begins at surface  12  and contains seating nipple  48 , upper perforated sub  23 , blank sub  42 , lower perforated sub  24 , one way valve  39 , on-off tool  26 , packer  14 , bushing  25  and terminates in curve  8  or lateral  10 . Seating nipple  48 , blank sub  42 , perforated subs  23 ,  24 , on-off tool  26 , packer  14 , one way valve  39 , and bushing  25  are all available from Weatherford International of Houston, Tex., among others. Connected to seating nipple  48  is pump  5  which is connected to sucker rods  11  which continue up to surface  12 . Connected to bushing  25  is second tubing string  21  which is connected to one way valve  28 , and continues down the wellbore and may terminate prior to the end of tubing  1 . 
     The process may be as follows. Reservoir fluids  7  emanate from reservoir  9  and enter lateral  10  and then enter first tubing string  1  and second tubing string  21 . Gas in reservoir fluids  7  expand inside second tubing string  21  and lift reservoir fluids  7  up and out of second tubing string  21  into first tubing string  1 , through on-off tool  26 , through one way valve  39  and out of lower perforated sub  24  and into annulus  2 . Reservoir fluids  7  separate into liquids  17  and annular gas  4 . Liquids  17  enter into upper perforated sub  23  and then enter into pump  5  where they become pumped liquids  13  and are pumped to surface  12  via tubing  1 . Annular gas  4  rises up annulus  2  to surface  12 . 
       FIG. 16  is the embodiment of  FIG. 15  except in a vertical wellbore. 
       FIG. 17  is the embodiment of  FIG. 16  except that a plunger has been installed in place of the sucker rods and pump. The plunger may be operated merely by the periodic opening and closing of the first tubing string  1  to the surface or it may be operated by the periodic or continuous injection of gas down the annulus combined with the periodic opening and closing of the first tubing string  1  to the surface. Both methods will force the plunger and liquids above it to the surface. This embodiment is much less expensive than installing a downhole pump. This design is advantageous for wells that have sufficient reservoir energy and gas production to lift liquids from below the downhole pump to above the downhole pump, yet still require artificial lift equipment to lift these liquids to the surface. This embodiment is less costly to install since no injection gas from the surface is required. Subsequently there is no gas injection tubing, no surface tank, no actuated valve, no compressor, and no dual string anchor. It will also accommodate wellbores with smaller casing diameters. 
     The embodiment of  FIGS. 15-16  is advantageous for wells that have sufficient reservoir energy and gas production to lift liquids from below the downhole pump to above the downhole pump, yet still require artificial lift equipment to lift these liquids to the surface. This embodiment is less costly to install since no injection gas from the surface is required. There does not have to be any gas injection tubing, surface tank, actuated valve, compressor, or dual string anchor. It will also accommodate wellbores with smaller casing diameters. The embodiment of  FIG. 17  is even less expensive because there does not have to be any downhole pump and related equipment. 
     An advantages of all embodiments is a lower artificial lift point and better recovery of hydrocarbons. There is better gas and particulate separation in all embodiments. In  FIGS. 3-11 , the entry point for the commingled fluids is above the intake of the pump or other fluid displacement device, which helps break out any gas in the fluids since gravity will segregate the gas from the liquids. The same is true for particulates since there is a large reservoir for them to collect in below the pump. In  FIGS. 12-17 , the gas is discouraged from entering the perforated subs because of gravity separation. 
     Because many varying and different embodiments may be made within the scope of the invention concept taught herein which may involve many modifications in the embodiments herein detailed in accordance with the descriptive requirements of the law, it is to be understood that the details herein are to be interpreted as illustrative and not in a limiting sense.