Patent Publication Number: US-2007114038-A1

Title: Well production by fluid lifting

Description:
BACKGROUND OF THE INVENTION  
      1. Field of the Invention  
      The present invention relates to methods and apparatus for enhancing the extractive flow of crude petroleum from production wells.  
      2. Description of Related Art  
      When a petroleum extraction well is first completed, in situ formation pressure is often sufficient to drive the formation fluid (crude oil) to the surface. Over time, with the continued extraction of the in situ fluid, the original formation pressure declines to the point of insufficient internal energy to drive a flow of fluid to the surface. This circumstance is exacerbated by the frequent invasion of water and other contaminating fluids into the formation interstices vacated by the original formation fluid. These contaminating fluids ultimately find their way into the production flow stream and into the well production tube. Due to a greater specific gravity of water than oil, the well production tube slowly fills with water to prevent all fluid extraction flow.  
      Unfortunately, natural production flow cessation may occur before even half of the in situ petroleum is drained. By some geological theories, the “depleted” fields of the world still contain at least as much petroleum as was originally extracted.  
      If the affected well is sufficiently shallow and sufficiently perpendicular to the earth&#39;s center, fluid production of a well originally produced by natural drive force may be continued by pumping. In such cases, the original production tube is withdrawn from the well and replaced by a sucker rod assembly. Sucker rod assemblies are mechanical lifts comprising a reciprocating rod disposed coaxially within a specialized production tube. The reciprocating rod supports a plurality of annular piston elements having opposite faces linked by pressure differentially operated check valves. The upper or surface end of the reciprocation rod is mechanically manipulated in a reciprocating motion to lift the formation fluid to the surface along the rod tube in successive increments. As with most reciprocating machines, sucker rod assemblies are expensive to position and to maintain.  
      Production inducements for deviated well bores and extremely deep wells are more difficult. In some of these examples, production has been enhanced by a process known to the art as “gas lifting”. Gas lifting includes the step of positioning a specialized formation fluid production tube within the well having one or more gas—lift valves strategically positioned along the length of the tube. The open, lower end of the production tube extends into the formation production zone. The well casing annulus between the external tubing wall and the internal casing wall at a point above the production zone is sealed by a packer to isolate the well production zone from the casing annulus above the zone.  
      The gas-lift valves are essentially pressure differentially controlled valves that link the internal flow bore of the fluid production tube with the external annulus volume between the production tube exterior and the well casing interior. A non-oxidizing gas such as methane, natural gas, or cryogenic nitrogen is charged under pressure into the casing annulus. When the designated pressure differential between the casing annulus and the tubing flow bore is attained, the lift valve opens to admit the gas into the flow bore. The higher pressure gas entrains the non-flowing fluid in the tubing flow bore with liquid displacing bubbles that enlarge as they rise to the surface of the production tube. This rising bubble expansion pushes the previously static flow bore fluid up and out of the tube at the surface. Additionally, the gas bubble entrainment reduces the density of the standing fluid column thereby reducing the positive, bottomhole head pressure that has prevented production flow in the first place. Fresh formation fluid is allowed to drain into the production zone of the well and into the production tube flow bore.  
      This process is continued with a continuing injection of gas into the well casing annulus at the wellhead. As the fluid pressure gradient within the tubing flow bore declines, additional lift valves open down the length of the production tube to further reduce the formation zone pressure until a net flow of new formation fluid is produced at the surface end of the production tube.  
      Although operationally effective, in many cases the process is economically marginal or negative due to the cost of the gas to drive the process. If low cost natural gas is available, the process may be profitable. If not, compressed methane or cryogenic nitrogen is the usual alternative. Production by means of the alternative gases is rarely profitable.  
      It is, therefore, an object of the present invention to teach a more economical process for fluid lifting the production of crude oil from a well.  
      It is also and object of the present invention to disclose a combination of well production equipment that economically facilitates the practice of the present invention process.  
      Another object of the present invention is to teach a method of opening the flow of a shut-in well without removing a pre-positioned production tube.  
     SUMMARY OF THE INVENTION  
      These and other objects of the invention are accomplished by one preferred embodiment in which a pre-positioned production tube is wire-line or slick-line perforated at a point above the production zone packer and, preferably, below or proximate of an oil-water interface standing in the production tube flow bore. A suitable fluid having a density less than water such as gaseous nitrogen, oxygen depleted air (non-cryogenic nitrogen) or carbon dioxide is charged into the well casing annulus above the production zone packer.  
      Pressure of the charging fluid bears against the surface of any fluid standing the casing annulus to force it into the tubing flow bore through the perforations. Initially, the pressure induced casing fluid flow will translate in both directions, up and down the tubing bore. However, the tubing down-flow capacity is limited. Hence, the flow is forced upward and out of the tubing flow bore at the surface. Continued charging expunges all of the static overburden fluid from the tubing and replaces it with a fluid that is lighter than water.  
      With the overburden fluid removed from the tubing flow bore, the overburden fluid being replaced by the lighter charging fluid, the charging fluid pressure may, in some cases, be reduced to permit a flow resumption of formation fluid into the production zone and up the production tube.  
      Another preferred embodiment of the invention also includes wire-line or slick-line perforation of the pre-existing production tube at a point above the tubing bottom packer. Internally of the tubing flow bore, a wire-line set tubing stop is positioned below the perforation. The landing nipple of a jet pump is positioned within the tubing stop to project a flow bore opening below the tubing stop. The outside surface (OD) of the jet pump upper end is sealed to the inside wall of the tubing flow bore by a top hold-down packer. The nozzle inlet orifices for the jet pump driving fluid flow are positioned within an annulus volume between the outside surface of the jet pump and the inside wall surface of the production tube. This annulus volume is axially delineated between the top hold-down packer and the bottom tubing stop.  
      As with the first embodiment of the invention, charging fluid enters the casing annulus at or near the wellhead to bear against the standing fluid surface thereby driving any standing annulus fluid through the preset tubing perforations and into the aspirator nozzle inlets. Discharge of fluid flow from the nozzle is channeled through an aspirator orifice to induce a low pressure zone within the jet pump body upstream of the orifice. This low pressure zone is flow line linked with the well production zone thereby inducing a formation fluid drainage into the jet pump landing nipple and up the production tube.  
      A third embodiment of the invention entails one or more gas-lift valves in side-pocket mandrels. These side pocket mandrels are flow carrier increments in production tubing string. Below the bottom-most gas-lift valve but above tubing packer a jet pump sub is positioned in the mandrel tubing string.  
      As charging gas sequentially opens the gas-lift valves starting from the top and advancing downwardly, the overburden fluid is removed up the tubing string. As the tubing flow bore back-pressure declines due to fluid extraction above the open lift valve, the open valve closes and the next lower valve opens.  
      This sequence continues until all lift valves have opened and closed. Only the jet pump remains open to continue aspirating the production zone. 
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS  
      Relative to the drawings wherein like reference characters designate like or similar elements throughout the several figures of the drawings:  
       FIG. 1  is a typical prior art well schematic shown in axial cross section;  
       FIG. 2  is an axial cross-section representing the first embodiment of the invention;  
       FIG. 3  is an axial cross-section representing the second embodiment of the invention;  
       FIG. 4  is sectioned detail of the jet pump section of the second embodiment;  
       FIG. 5  is an elevation view of jet pump sub embodiment of the invention  
       FIG. 6  is a schematic view of the invention embodiment that combines a gas-lift valve in the jet pump tubing string. 
    
    
     DESCRIPTION OF THE PREFERRED EMBODIMENTS  
      The environment of utility for the present invention is generally represented by  FIG. 1  as a Prior Art schematic of an oil well. The well comprises a raw borehole  12  drilled through the earth formations  10  into a productive formation  13 . In many cases, a casing pipe  14  is extended along the borehole for a predetermined portion of the borehole depth and secured in place by an annular collar of cement  16 .  
      At a depth corresponding with the production formation  13 , the casing  14  and cement  16 , if present, is perforated by numerous apertures and fissures  18 . The perforations  18  facilitate the drainage flow of formation fluid into a production zone  20  within the casing interior.  
      Often, the borehole  12  continues past the production formation. In these circumstances, the borehole  12 , or if cased  14 , may be obstructed with a plug packer  22  secured below the production zone  20 .  
      A well with sufficient pressure in the production formation  13  to drive the drainage fluid to the surface may be produced through the open flow bore of a production tube  24 . The O.D. surface of the bottomhole end of the production tube  24  is sealed to the interior wall face of the casing  14  or borehole wall by means of a tubing packer  26 . The open end  25  of the production tube flow bore below the packer  26  extends into the well production zone  28 . Although the inflow end  25  of the production tube  24  flow bore is graphically represented here by  FIG. 1  as an axially biased cross-cut, in normal practice, however, the inflow end of a production tube is a screened opening into the interior production tube flow bore.  
      As the production formation  13  is drained of in situ petroleum, water may seep into the formation to fill the formation interstices vacated by the extracted petroleum. Such migrant water also finds its way into production zone flow and up the production tube  24 . Over time and continued production, the oil/water ratio of the production tube flow stream decreases with a consequent increase in the tubing flow column density. Eventually, the standing fluid head within the column exerts a bottomhole pressure that equals the in situ formation pressure. At that point the production flow at the surface stops and the fluid column within the production tube  24  is static.  
      Standing statically in the tubing flow bore, fluids of different specific weights will separate, more or less, into respective strata. For example, the top or upper strata  30 , being the less dense fluid, may be predominately oil. Below the oil is a heavier water column  32 . Although described herein by the term “water”, the aqueous well bore fluid usually comprises a mixture of water, acid and emulsified petroleum. The two immiscible fluid columns meet at a contiguous interface  34 . Although the originally mixed fluids separate in the tubing column, the total head pressure above the production zone  20  remains the same; substantially equal to the in situ formation pressure.  
      Depending on the integrity of the packer  26  and/or the continuity of the casing  14  wall, a column of water  36  may also accumulate in the borehole or casing annulus  15 .  
      In a first embodiment of the invention, represented by  FIG. 2 , for example, restoration of productive flow from a “depleted” well includes the preparatory step of securing an injection flow connection  42  proximate of the wellhead  40  for injecting pressurized charging fluid into the casing annulus  15 . The charging fluid is preferably oxygen depleted air such as non-cryogenic nitrogen. However, other non oxidizing fluids such as natural gas, methane, carbon dioxide may also be suitable depending on the well site economics.  
      Further to the charging fluid connection,  42 , the preexisting production tube  24  is in situ perforated at a strategic point  44  above the packer  26 . Usually, in situ production tube perforations are executed by a “slick line” or wire-line operation that includes a small diameter perforating gun suspended from the surface at the end of a wire-line. The depth of tubing perforation is selected to sufficiently reduce the tubing column overburden pressure sufficient to restore production flow.  
      Compressed charging fluid  50  enters the well casing annulus  15  through the injection flow connection  42  to bear upon the surface  38  of any fluid column that may be standing in the annulus. With the surface discharge end  46  of the tubing  24  flow bore open into a discharge zone, annulus fluid is driven through the perforations  44 . There being no volumetric accommodation for flow displacement downwardly, the top pressure driven annulus fluid escapes up the tubing flow bore pushing the static fluid column in the tubing flow bore ahead and out of the tube at the surface.  
      When the surface  38  of the annulus fluid column  36  is driven below the tubing perforations  44 , the remaining fluid column in the tubing flow bore begins entrainment by the lighter charging fluid. As the rising charging fluid displaces the flow bore liquid from the surface discharge zone  46  of the tube, the overburden pressure on the production zone begins to decline. At this point, residual in situ formation pressure begins to push additional formation fluid into the production zone  20  and up the tubing  24  flow bore where it joins the charging fluid mixture zone proximate of the perforations  44 .  
      Usually, the resumed flow of formation fluid comprises the same mixture of oil and water that originally terminated the well production. Consequently, it is frequently necessary to continue injection of the charging fluid to sustain the production fluid flow. However, a reduction of the charging fluid flow rate and pressure may be permitted after the original water head is discharged. Moreover, the majority of charging fluid is normally recyclable. Hence, sustained production flow is economically burdened only by the cost of charging fluid compression and loss replenishment.  
      Except for the charging fluid compression apparatus, which is normally surface positioned and operated, the process includes no dynamic machine elements subject to wear or structural failure.  
      A second embodiment of the invention is represented by the schematic of  FIG. 3  and detail of  FIG. 4 . As with the first embodiment, a preexisting production tube  24  stands within the casing  14 . The tube  24  supports a static head of production fluid that may have gravimetrically separated into lighter and heavier liquid elements. The production tube O.D. is sealed to the casing l.D. wall by means of a packer  26 .  
      This  FIG. 3  invention embodiment also includes in situ perforations  44  of the preexisting tubing. Additionally, however, a tubing stop  52  is secured, for example, by wire-line manipulation to the l.D. wall of the tubing  24  below the perforations  44  as best illustrated by  FIG. 4 . The jet pump assembly  55  includes a landing nipple  54  that is seated within an axial aperture of the tubing stop  52 . The upper end of the jet pump  55  is aligned and secured by a top hold-down packer  56  that is strategically positioned above the tubing apertures  44 . This alignment of elements creates an aspirator nozzle supply plenum  58  around the jet pump  55  linked by the tube perforation apertures  44  to the casing annulus  15 . The nozzle supply plenum  58  serves as a fluid supply reservoir for charging fluid flow into the aspirator nozzle inlet orifice  62 .  
      Operationally, the second invention embodiment is similar to the first embodiment in that the charging fluid is channeled into the casing annulus  15  via an injection flow fitting  42  to pressure load a standing fluid column  36  in the casing annulus  15 . Casing annulus fluid  36  is displaced under the pressure load through the tubing apertures  44  into the nozzle supply plenum  58 . From the nozzle supply plenum  58 , fluid is driven through the orifice  62  for high velocity jet discharge from the nozzle  60 . The high velocity jet discharge is directed through a larger diameter aspirator nozzle  64  to generate a low pressure flow induction zone at the jet pump inlet  66 .  
      Referring to the detail of  FIG. 4 , attention is directed to the check valve  70  in the nozzle  60 . This illustrated embodiment of a check valve comprises a ball  72  caged between a ball valve seat and a gage- pin  74 . Fluid flow entering the nozzle inlet  66  lifts the ball  72  off the valve seat. The cage-pin  74  prevents the ball  72  from flowing out of the nozzle flow bore while the drive fluid flows around the valve ball  72 .  
      In the event that natural production flow is restored by removal of the tube  24  overburden fluid, it may be tolerable to eliminate the charging fluid flow. In such a case, the pressure differential between the tubing  24  flow bore and the jet pump secondary annulus  58  would reverse and the check valve ball  72  would pressure differentially seat to close the nozzle bore.  
      Although the jet pump aspirating principles are effective with a liquid charging fluid discharged from the nozzle  64 , the flow induction efficiency is considerably greater when the charging fluid is a compressed gas. When the compressed gas is released into the liquid filled tubing bore, the gas nucleates into numerous small bubbles, each containing a fixed, finite weight of gas. In conformance with Boyle&#39;s Law, as the bubbles rise in the tubing flow bore column, the fluid environment pressure declines. As the environment pressure declines, the fixed weight of gas charging fluid in each bubble volumetrically expands to accelerate the displacement of surrounding liquid.  
       FIGS. 5 and 6  illustrate a third embodiment of the invention that comprises a jet pump sub  80  that is line coupled in a straight tubing string  24  or below a side pocket mandrel tube  82 .  
      The jet pump sub  80  essentially conforms to the jet pump body  55  illustrated by  FIG. 4  with the exception that the nozzle inlet  62  is protected by a slotted screen  84 , for example.  
      Unless the original production tube is installed with the jet pump sub  80  in-line, which it may be, it will be necessary to withdraw the tubing  24  to insert the pump sub  80 . However, no wire-line or perforating procedures are necessary. The entire casing annulus becomes the charging fluid plenum for the pump sub  80 .  
      In the case of the  FIG. 6  embodiment, a gas-lift valve string  28  comprises several lift valves  90 ,  92  and  94 , for example. The valve orifices and mechanisms are disposed in side-pocket mandrel joints  82  above the jet pump  80 .  
      Operatively, the casing annulus  15  is charged with an opening pressure that, for example, may be 2000 psi for a lift-valve at 3000 ft. depth. If the flow bore head pressure is 1500 psi at that point, a 500 psi differential opening pressure may be necessary to open the first lift valve  90 .  
      Once lifting flow begins, the opening pressure differential declines. For example, is valve  94  is at 3500 ft., the internal flow bore head pressure may have declined to 1200 psi and only a 250 psi differential is required to open valve  94 . Hence, the casing annulus pressure may be reduced to 1450 psi.  
      At the same time that valve  94  is opening to 250 psi differential, this differential is insufficient to hold the valve  90  open. Hence, valve  90  closes at the approximate pressure differential that valve  92  opens considering the respective depth i.e. head, differential between valves  90  and  92 .  
      This sequence continues down the tubing string until all lift valves in the string  28  have opened and closed leaving only the jet pump  80  as transferring charging fluid from the casing annulus  15  into the production tube flow bore.  
      As is often the case with deep, gas drive well, the presence of excess water in the production flow stream may be intermittent. Consequently, the flow bore of a production tube may be purged of a stagnating water head and resume an unassisted production of petroleum for an indeterminate period. Eventually, however, another water flow will invade the production to stagnate the production. Advantageously, the invention embodiment of  FIG. 6  may be positioned as the original well completion and continued indefinitely by intermittently purging the flow bore of accumulated water and thereafter stopping the flow of external lifting gas to permit the natural drive production.  
      As used herein, the terms “up” and “down”, “upper” and “lower”, “upwardly” and “downwardly”, “upstream” and “downstream”, “above” and “below” and other like terms indicating relative positions above or below a given point or element are used in this description to more clearly describe some embodiments of the invention. However, when applied to equipment and methods for use in wells that are deviated or horizontal, such terms may refer to a left-to-right or right-to-left or other relationship as appropriate. Moreover, in this specification and appended claims, the terms “pipe”, “tube”; “tubular”, “casing”, “liner” and/or “other tubular goods” are to be interpreted and defined generically to mean any and all of such elements without limitation of industry usage.  
      Having fully described the presently known preferred embodiments of our invention, those of skill in the art will understand other obvious permutations and modifications of the invention. As definition of our invention, therefore,