Abstract:
A gas lift apparatus for use with a well bore sealing device includes a tubing string coupled to the well bore sealing device, a gas inlet port in the tubing string extending between the well bore above the sealing device and a flow bore in the tubing string to provide a first flow path, and a second flow path in the tubing string wherein the first flow bore extends the first fluid path to a location in the well bore below the sealing device and the second flow path. A method for producing a fluid from a well bore zone below a set sealing device disposed in a production tubing includes providing a gas to a well bore annulus formed by the production tubing, flowing the gas downwardly into the production tubing and then through the sealing device, flowing the gas through the well bore zone and then into the well bore zone and flowing the fluid upwardly through the well bore zone, then into the production tubing and through the sealing device to the surface of the well.

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
       [0001]    This application is a continuation of U.S. patent application Ser. No. 10/999,272 filed Nov. 29, 2004, hereby incorporated herein by reference. 
     
    
     STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT 
       [0002]    Not applicable. 
       FIELD OF THE INVENTION 
       [0003]    The present invention relates generally to apparatus and methods for use during gas-lift operations in a well bore. More particularly, the present invention relates to a ported velocity tube that delivers gas below a production packer to a perforated zone, and a cost-efficient method of unloading a well bore below a production packer. 
       BACKGROUND OF THE INVENTION 
       [0004]    Gas-lift operations may be employed in hydrocarbon wells as a primary recovery technique for lifting fluids, such as water or oil, from the well. One type of gas-lift operation comprises injecting gas downwardly from the surface into the well bore annulus formed between production tubing and the well bore wall or casing. As the gas is injected from the surface, it gradually reduces the density of the column of fluid in the well from top to bottom. As the density of the fluid is reduced, the fluid becomes lighter until the natural formation pressure is sufficient to push the fluid up and out of the well through the production tubing, typically through gas-lift valves disposed at spaced locations along the production tubing. 
         [0005]    Using this gas-lift method, a completed well that is ready to be placed on production, for example, may be unloaded of water to thereby remove the hydrostatic head created by the water and enable the flow of the lighter produced hydrocarbons from the formation into the well bore. When gas-lift valves are employed to unload the well, the well bore annulus may be packed off below the gas-lift valves to reduce the volume of fluid that must be lightened by the gas and unloaded through the valves. The gas-lift valves close sequentially from top to bottom automatically when the fluid has been lifted out through the production tubing and injection gas remains in the well bore annulus at that depth. By this means, each succeeding lower gas-lift valve is closed as the fluid level in the annulus is successively lowered until the lowermost gas-lift valve is exposed to the injection gas in the annulus. Thereafter, gas lift does not occur below the packer, but because the well bore annulus has been unloaded above the packer, the natural formation pressure may be sufficient to push the column of produced fluid up and out of the well through the production tubing. 
         [0006]    The above-described method may be sufficient for gas-lifting a standard length well. However, this method may be ineffective to gas-lift long, multi-zone or deviated production wells. In particular, a high pressure gas would be required to sufficiently lighten a very long column of fluid. However, it is undesirable to inject high pressure gas into the annulus because such gas would overcome the formation pressure and inject into the perforations, thereby preventing production fluids from flowing into the well. 
         [0007]    Gas-lifting operations for long, multi-zone or deviated production wells may be improved by using a production packer to seal the well bore annulus so that the well above the packer may be unloaded to thereby reduce the hydrostatic head. However, because gas cannot be injected below the packer, and because the packer must be set above the perforated zone, even using a packer may be insufficient to effectively gas-lift a well down to the last production interval when the well bore extends some distance beyond the packer. 
         [0008]    Other types of gas-lift operations exist, such as, for example, an inner string extending from the surface through the production tubing to inject gas into the fluid in the production tubing, but such apparatus and methods can be cost prohibitive. Therefore, a need exists for apparatus and methods to effectively gas-lift a long, multi-zone or deviated production well. In particular, a need exists for apparatus and methods that enable gas injection directly to the perforated zone below the production packer, and a cost-efficient method of unloading a well bore below a production packer. 
       SUMMARY OF THE INVENTION 
       [0009]    A gas lift apparatus is disclosed for use with a well bore sealing device including a tubing string coupled to the well bore sealing device, a gas inlet port in the tubing string extending between the well bore above the sealing device and a flow bore in the tubing string to provide a first flow path, and a second flow path in the tubing string wherein the first flow bore extends the first fluid path to a location in the well bore below the sealing device and the second flow path. In some embodiments, the gas lift apparatus further includes an inner string having the flow bore and the first flow path, and extending through the sealing device into the well bore below the sealing device and the tubing string. In other embodiments, the inner string is installable or removable by slick line when the apparatus is in the well bore. In certain embodiments, the inner string is disposed within a primary flow bore. In yet other embodiments, an annulus between the inner string and the primary flow bore includes the second flow path. In still other embodiments, the first and second flow paths are concentric. 
         [0010]    In another aspect, a gas lift apparatus is disclosed for use with a well bore sealing device including a production tubing, the well bore sealing device coupled to the production tubing, a gas inlet port disposed in the production tubing above the sealing device, an inner tubing string coupled to the production tubing and communicating with the gas inlet port to form a first flow path, and a second flow path in an annulus between the production tubing and the inner tubing string. 
         [0011]    In yet another aspect, a method is disclosed for producing a fluid from a well bore zone below a set sealing device disposed in a production tubing including providing a gas to a well bore annulus formed by the production tubing, flowing the gas downwardly into the production tubing and then through the sealing device, flowing the gas through the well bore zone and then into the well bore zone, and flowing the fluid upwardly through the well bore zone, then into the production tubing and through the sealing device to the surface of the well. 
     
    
     
       BRIEF SUMMARY OF THE DRAWINGS 
         [0012]      FIG. 1  is a schematic view, partially in cross-section, of an exemplary operating environment for a ported velocity tube, depicting a completion system disposed within a well bore extending into a subterranean hydrocarbon formation; 
           [0013]      FIG. 2  is an enlarged cross-sectional side view of one embodiment of a ported velocity tube; and 
           [0014]      FIG. 3  is an enlarged cross-sectional side view of the ported velocity tube of  FIG. 2 , depicting the inner string and other internal components of the ported velocity tube removed. 
       
    
    
     NOTATION AND NOMENCLATURE 
       [0015]    Certain terms are used throughout the following description and claims to refer to particular apparatus components. This document does not intend to distinguish between components that differ in name but not function. In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . ”. 
         [0016]    Reference to up or down will be made for purposes of description with “up”, “upper”, or “upstream” meaning toward the earth&#39;s surface and with “down”, “lower”, or “downstream” meaning toward the bottom of the well bore. 
       DETAILED DESCRIPTION 
       [0017]      FIG. 1  schematically depicts an operating environment for one embodiment of a ported velocity tube  100 , described in more detail below. As depicted, a completion system  10  extends downwardly into a well bore  20  to form a well bore annulus  22  therebetween. The well bore  20  penetrates a subterranean formation F for the purpose of recovering hydrocarbons, and at least a portion of the well bore  20  may be lined with casing  25  that is cemented  30  into position against the formation F in a conventional manner. Perforations  35  extend through the casing  25  and cement  30  into a lowermost producing zone A in the formation F to provide a path for the flow of fluids from the producing zone A into the well bore  20 . 
         [0018]    The completion system  10  may take a variety of different forms. In the embodiment depicted in  FIG. 1 , the completion system  10  comprises a plurality of gas-lift valves  40  spaced along a production tubing  50 , a ported velocity tube  100  (referred to hereinafter as PVT  100 ), a production packer  60 , and an inner tubing string  70  suspended from the PVT  100  and extending through the production packer  60  to form a flow annulus  80  within the packer  60 . In an embodiment, an injection valve  90  and a bull plug  95  may also be connected toward the lower end of the inner tubing string  70 , which terminates adjacent the perforations  35 . While the completion system  10  shown in  FIG. 1  depicts a quantity of five gas-lift valves  40 , one of ordinary skill in the art will readily appreciate that the number and spacing of gas-lift valves  40  may change without departing from the scope of the present invention. Additional components may also be provided as part of the completion system  10 . 
         [0019]    In an embodiment, the production packer  60  is a standard, double-grip production packer, such as the M1-X™ packer or the Versalock™ packer, both available from Smith International, Inc. of Houston, Tex. The production packer  60  is set against the casing  25  to thereby form a plug that isolates an upper portion  24  from a lower portion  26  of the well  20 . The PVT  100  enables gas that is injected into the well bore annulus  22  to flow from the upper well bore portion  24  to the lower well bore portion  26  through the inner tubing string  70 , as will be described in more detail herein. 
         [0020]      FIG. 2  depicts an enlarged cross-sectional side view of one embodiment of the PVT  100  comprising a top sub  110  with longitudinal flow bore  105 , a bypass connector  120  with a longitudinal flow bore  125 , and a bottom sub  130  with a longitudinal flow bore  135 . The top sub  110  connects via threads  112 , set screws  114 , and O-ring seals  116  to the bypass connector  120 ; which in turn connects via threads  132 , set screws  134 , and O-ring seals  136  to the bottom sub  130 . The bypass connector  120  comprises an inlet port  122  that extends radially through a wall  123  of the bypass connector  120  to provide fluid communication with the well bore annulus  22 . The bypass connector  120  further comprises a return port  126  that extends longitudinally through the wall  123  of the bypass connector  120 . API connectors  111 ,  131  are provided at the upper and lower ends of the PVT  100 , respectively, for connecting the PVT  100  to other components, such as the production tubing  50  on the upper end and the packer  60  on the lower end, for example. 
         [0021]    Still referring to  FIG. 2 , the PVT  100  further comprises a landing sub  140 , a blanking plug  150 , V-packing seals  160 , and a tubing crossover sub  170  all disposed within the bore  125  of the bypass connector  120  and extending into the bore  135  of the bottom sub  130 . The landing sub  140  connects via threads  152  to the blanking plug  150 , which in turn connects via threads  172  and O-ring seals  174  to the tubing crossover sub  170 . The tubing crossover sub  170  includes a lower threaded end  176  to connect to the inner tubing string  70  that extends through the packer  60  into the lower well bore portion  26  as depicted in  FIG. 1 . 
         [0022]    Referring now to  FIG. 2  and  FIG. 3 , the landing sub  140  comprises a standard slick line profile  142  that enables slick line retrieval and/or installation of the internal components, namely the landing sub  140 , blanking plug  150 , V-packing seals  160 , tubing crossover sub  170 , and the inner tubing string  70 , when the PVT  100  is already disposed in the well  20 .  FIG. 3  depicts the PVT  100  after removal of these internal components  140 ,  150 ,  160 ,  170 , and  70 , which may be desirable for a variety of reasons during operation. For example, if a leak develops in any of these internal components  140 ,  150 ,  160 ,  170  and  70 , a slick line can be run down to engage the upper profile  142  and retrieve the components for field replacement. Then the slick line can run the landing sub  140 , blanking plug  150 , V-packing seals  160 , tubing crossover sub  170 , and the inner tubing string  70  back into the well  20  for re-installation in the PVT  100 . As shown in  FIG. 3 , bypass connector  120  comprises an internal shoulder  128  corresponding to an external shoulder  175  on the tubing crossover sub  170  as shown in  FIG. 2 . The internal shoulder  128  thereby provides a stop for the external shoulder  175  for proper positioning of the internal components  140 ,  150 ,  160 ,  170  and  70  within the PVT  100  when they are installed via slick line. 
         [0023]    Referring now to  FIG. 2 , the blanking plug  150  comprises a plug portion  154  that acts to block fluid flow downwardly through the bore  125  of the bypass connector  120 , and a flow bore  156  in fluid communication at its upper end with the inlet port  122  of the bypass connector  120 . Flow bore  156  is also in fluid communication with a flow bore  178  in the tubing crossover sub  170 , which in turn is in fluid communication with the bore  75  of the inner tubing string  70 . Thus, inlet port  122  and flow bores  156 ,  178 ,  75  thereby provide a continuous fluid flow path for fluid communication between the upper well bore portion  24  and the lower well bore portion  26 . V-packing seals  160  are disposed between the blanking plug  150  and the bypass connector  120 , above and below the inlet port  122  of the bypass connector  120 , and the seals  160  are held in place by set screws  162 ,  164 , respectively. The plug portion  154  and the V-packing seals  160  act to isolate the inlet port  122  from fluid disposed in the bore  125  of the bypass connector  120 . 
         [0024]    In operation, the PVT  100  provides a path for gas that is injected into the well bore annulus  22  to flow from the upper portion  24  of the well  20  to the lower portion  26  of the well  20  to enable gas-lift operations below the set packer  60 . Referring again to  FIG. 1 , after the completion assembly  10  is run into the well bore  20 , and the packer  60  has been set against the casing  25 , the wellhead (not shown) is installed at the surface to maintain control of the well  20 . Then the well  20  is ready to be placed on production. However, the well bore annulus  22  is full of water that was previously used for well control before the wellhead was installed. Therefore, the water must be removed from the well  20  to allow fluid flow out of the production zone A of the formation F through the perforations  35 . Thus, in an embodiment, the water is unloaded from the well bore annulus  22  via conventional gas-lift methods above the packer  60 . Namely, gas is injected from the surface into the well bore annulus  22  until the density of the water is reduced sufficiently to allow natural formation pressure to push the water out of the well  20 . The water may be unloaded through the production tubing  50  to the surface of the well  20  using the gas-lift valves  40 , which automatically open sequentially from top to bottom. This gas-lift operation continues until gas reaches the PVT  100  in the upper portion  24  of the well  20 . In an embodiment, the gas-lift valves  40  are used only for unloading the upper portion  24  of the well  20  above the packer  60  before the gas flow is routed through the PVT  100 , at which point the gas-lift valves  40  are inactive and remain closed. 
         [0025]    Once the water has been unloaded from the upper portion  24  of the well  20 , gas that is injected into the annulus  22  flows downwardly to the PVT  100 , as represented by flow arrows  300  in  FIG. 1 . As shown in  FIG. 1  and  FIG. 2 , the gas flow continues through the inlet port  122  of the PVT  100  as indicated by flow arrow  310 , which leads into the flow bores  156 ,  178  of the blanking plug  150  and crossover tubing connector  170 , respectively, as indicated by flow arrows  320 . The flow continues downwardly through the packer  60  via the inner tubing string  70 , and emerges along flow path  330  to finally jet outwardly through the injection valve  90  as indicated by flow arrow  340  into the lower portion  26  of the well bore  20  adjacent the perforations  35 . If the gas contains any debris, at least some of that debris will fall out and be captured within the section  78  of tubing string  70  below the injection valve  90 , which is plugged at the bottom by bull plug  95 . 
         [0026]    As the gas jets out into the lower portion  26  of the well  20 , the gas mixes with the production fluid to lighten the fluid until the bottomhole pressure of the formation F is sufficient to push the production fluid upwardly along flow path  350  through the packer  60  via the flow annulus  80  formed between the inner tubing string  70  and the bore of the packer  60 . As the production fluid continues to flow upwardly, it will be routed along flow path  360  into the PVT  100 . This fluid flow will continue along path  370  through the return port  126  and into the longitudinal flow bore  105  of the top sub  110 . The production fluid continues to flow upwardly along path  380  through the production tubing  50  and up to the surface of the well  20 . As indicated by the flow arrows  310 ,  320 ,  370  shown in  FIG. 1  and  FIG. 2 , the PVT  100  is designed to accommodate gas flow through inlet port  122  and production fluid flow through return port  126  simultaneously. In one embodiment of the method for gas-lifting a well  20  below a production packer  60 , the gas injection and return of production fluid to the surface is a continuous operation. 
         [0027]    Therefore, the PVT  100  is a simple device with no moving parts that is designed for gas-lift operations to enhance liquid recovery by decreasing the fluid density and increasing the gas lifting power below the production packer  60 . The PVT  100  works with a standard, low-cost, double-grip packer  60  so that fluid above the packer  60  can be unloaded from the well  20  via the gas-lift valves  40 , and then gas can be injected through the PVT  100  to lighten the produced fluid in the lower portion  26  of the well so that it can be lifted through the production tubing  50  to the surface of the well  20 . With proper placement of the inner tubing string  70 , the benefits of gas lift can be achieved even at the lowermost producing zone A. In particular, gas can be delivered directly to the perforations  35  extending into producing zone A, making the PVT  100  particularly useful in wells  20  with multi-production zones or in deviated wells where the packer  60  has to be set a great distance from the perforations  35 . The inner tubing string  70  can be run in place with the completion system  10 , or may be run through the production tubing  50  on slick line and landed in the PVT  100 . The PVT  100  is expected to enhance hydrocarbon fluid recovery for most gas-lift operations, either onshore or offshore. In an embodiment, at least some of the components of the PVT  100  comprise L80 grade steel or stainless steel, thereby making the PVT  100  suitable for sour production service or other liquid services. 
         [0028]    The foregoing descriptions of specific embodiments of the completion system  10  and PVT  100 , as well as the methods for unloading a well  20  below a production packer  60 , were presented for purposes of illustration and description and are not intended to be exhaustive or to limit the apparatus and methods to the precise forms disclosed. Obviously many other modifications and variations are possible. In particular, the type of completion system  10 , or the particular components that make up the completion  10  may be varied. Further, the placement of the PVT  100  within the well bore  20  may be varied. For example, the PVT  100  could be positioned anywhere along the completion system  10  or within the well bore annulus  22 , so long as it functions to inject gas into the lower portion  26  of the well bore  20  below the production packer  60 . Many other variations, combinations, and modifications of the invention disclosed herein are possible and are within the scope of the invention, and as such, the embodiments described here are exemplary only, and are not intended to be limiting. 
         [0029]    Accordingly, while various embodiments of the invention have been shown and described herein, modifications may be made by one skilled in the art without departing from the spirit and the teachings of the invention. The different teachings of the embodiments discussed herein may be employed separately or in any suitable combination to produce desired results. Accordingly, the scope of protection is not limited by the description set out above, but is defined by the claims which follow, that scope including all equivalents of the subject matter of the claims.