Abstract:
An artificial lift system is disclosed for removing reservoir fluids from a wellbore. A downhole pump and a gas lift system are disposed in the wellbore. The gas lift system includes a first tubing string, and the downhole pump may be positioned with a second tubing string. Injected pressured gas from the gas lift system may commingle with and raise reservoir fluids from the wellbore through the first tubing string. The commingled gas and reservoir fluids may be separated in the wellbore, and the reservoir liquids may be brought to the surface through the second tubing string by the pump.

Description:
BACKGROUND OF THE INVENTION 
     I. Field of the Invention 
     The present invention relates to artificial lift production systems and methods deployed in subterranean oil and gas wells, and more particularly relates to artificial lift production systems and methods for removing wellbore liquids from directional or horizontal wellbores. 
     II. Background and Prior 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 industry are down-hole pumping 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. The plunger is lowered into a well by a string of rods contained inside a production tubing string. A pump jack at the surface provides the reciprocating motion to the rods which in turn provides the reciprocal motion to stroke the pump. 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. The invention will also function with other downhole pump systems such as progressive cavity, jet, electric submersible pumps and others. 
     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. Depletion or partial depletion drive reservoirs undergo a pressure decline as reservoir 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 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 since down-hole equipment installed in these regions can undergo high maintenance costs. Therefore, most operators only install down-hole artificial lift equipment in the vertical portion of the wellbore. However, downhole pump systems and compressed gas lift systems are not designed to recover any liquids that exist below the down-hole equipment. In many directional and horizontal wells, a column of liquid ranging from 300 to many thousands of feet may exist below the down-hole equipment installed in the vertical portion of the wellbore. Because of this condition considerable hydrocarbons reserves cannot be recovered using conventional methods in depletion or partial depletion drive directional or horizontally drilled wells. Thus, a major problem with the current technology is that reservoir liquids located below conventional down-hole artificial lift equipment cannot be lifted. 
     Therefore, one object of the present invention is to provide an artificial lift system that will enable the recovery of liquids in the deviated sections of directional or horizontal wellbores. 
     It is also an object of the present invention to lower the artificial lift point from the vertical wellbore section into the deviated section. 
     It is also an object of the present invention to provide a high velocity volume of injection gas to more efficiently sweep the reservoir liquids from the wellbore. 
     A further object of the present invention is to provide a more efficient, less costly wellbore liquid removal process. 
     These and other objects of the present invention will become better understood with reference to the following specification and claims. 
     SUMMARY OF THE INVENTION 
     A gas assisted downhole pump is disclosed, which is an artificial lift system designed to recover by-passed hydrocarbons in directional and horizontal wellbores by incorporating a dual tubing arrangement in which each string contains (respectively) a downhole pumping system or a gas lift system. In one string, a gas lift system (preferably intermittent) is utilized to lift reservoir fluids 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 (which is installed in the adjacent string), and the trapped reservoir fluids are pumped to the surface by the downhole pump. 
    
    
     
       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 one version of the invention utilizing a rod pump and a gas lift system; 
         FIG. 4  depicts another embodiment of the invention similar to  FIG. 3 ; 
         FIG. 5  depicts yet another embodiment of the invention similar to the  FIG. 3 , but with a different downhole configuration; and 
         FIG. 6  depicts another embodiment of the invention similar to  FIG. 5 . 
     
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS 
       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  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 is 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, it separates into annular gas  4  and liquids  17 . Annular gas  4  emanates 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  15 . 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 , the conventional gas lift valve  15  opens and allows the injection gas  16  to pass from the annulus  2  into the tubing  1 , which then commingles with the reservoir fluids  7  to become gas lifted liquids  13 . This lightens the fluid column and the gas lifted liquids  13  rise up the tubing  1  and then flow out of the well to the surface  12 . 
       FIG. 3  shows the preferred embodiment of the invention 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 the surface  12  and contains internal gas lift valve  15 , bushing  25 , and inner concentric tubing  21 . Tubing  1  is sealingly engaged to packer  14 . Tubing  1  and inner concentric tubing  21 , extend below packer  14  through curve  8  and into lateral  10 , which is drilled though reservoir  9 . Inside casing  6  and adjacent to tubing  1  is tubing  3  which contains pump  5  and sucker rods  11 . Tubing  3  is not sealingly engaged to packer  14 . The process is as follows: reservoir fluids  7  enter lateral  10  and rise up curve  8  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 concentric tubing  21  and tubing  1 . The commingled fluids  18  then exit through holes in perforated sub  24 . Annular gas  4  separates from commingled fluids  18  and rise in annulus  2 , which is formed by the void space between casing  6  and tubing  1  and tubing  3 . Annular gas  4  then enters flowline  30  at the surface  12  and enters compressor  38  to become compressed gas  33 , and travels through flowline  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 flowline  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 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 . The injection gas  16  then enters the inner concentric tubing  21 , and eventually commingles with reservoir fluids  7  to become commingled fluids  18 , and the process begins again. The liquids  17  separate from the commingled fluids  18  and fall in annulus  2  and are trapped above packer  14 . As more liquids  17  are added to the annulus  2 , liquids  17  rise above and are gravity fed into pump  5  to become pumped liquids  13  which travel up tubing  3  to the surface  12 . 
       FIG. 4  shows an alternate embodiment of the invention 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 of the invention 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  18  which in turn is connected to chamber outer tubing  20 . Chamber outer tubing  20  continues below casing  6  through curve  8  and into lateral  10  which is drilled through reservoir  9 . Inner concentric tubing  21  is secured by chamber bushing  22  to one of the tubular members of Y Block  18  leading to lower tubing section  37 . The inner concentric tubing  21  extends inside of Y block  18  and outer chamber tubing  20  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 standing valve  23  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  28 , a perforated inner tubular member  27 , a cross over sub  29  and tubing  3  which contains pump  5  and sucker rods  11 . The gas shroud  28  is tubular in shape and is closed at its lower end and open at its upper end. It surrounds perforated inner tubular member  27 , which extends above gas shroud  28  to crossover sub  29  and connects to the tubing  3 , which continues to the surface  12 . Above the crossover sub  29 , 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 flow-line  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 flow-line  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  18  and into chamber annulus  19 , which is the void space between inner concentric tubing  21  and chamber outer tubing  20 . Injection gas  16  is forced to flow down chamber annulus  19  since its upper end is isolated by chamber bushing  22 . 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  18 , through packer  14  and standing valve  23 , 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  23 . As liquids  17  accumulate in annulus  2 , they rise above pump  5  and are forced by gravity to enter inside of gas shroud  28  and into perforated sub  26  where they travel up inner tubular member  27  and cross-over sub  29  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 . 
     As can be seen from the foregoing description of the preferred and alternate embodiments, the present invention is intended to provide an artificial lift system. Because many varying and difference 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.