Patent Abstract:
The present invention provides a method and apparatus whereby the intake pipeline running between the production chamber of a natural gas well and the suction inlet of an associated wellhead compressor is completely enclosed, in airtight fashion, within a jacket of natural gas under positive pressure (i.e., higher than atmospheric). Being enclosed inside this “positive pressure jacket”, the intake pipeline is not exposed to the atmosphere at any point. This allows gas to be drawn into the compressor through the intake pipeline under a negative pressure, without risk of air entering the intake pipeline should a leak occur in the pipeline. If such a leak occurs, there will merely be a harmless transfer of gas from the positive pressure jacket into the intake pipeline. If a leak occurs in the positive pressure jacket, gas therefrom will escape into the atmosphere, and entry of air into the positive pressure jacket will be impossible.

Full Description:
FIELD OF THE INVENTION  
       [0001]     The present invention relates to methods and apparatus for protecting against the influx of air into a pipeline carrying a combustible gas under negative pressure, and particularly to such methods and apparatus for use in association with a pipeline carrying natural gas under negative pressure from a natural gas well to a gas compressor.  
       BACKGROUND OF THE INVENTION  
       [0002]     Natural gas is commonly found in subsurface geological formations such as deposits of granular material (e.g., sand or gravel) or porous rock. Production of natural gas from these types of formations typically involves drilling a well a desired depth into the formation, installing a casing in the wellbore (to keep the well bore from sloughing and collapsing), perforating the casing in the production zone (i.e., the portion of the well that penetrates the gas-bearing formation) so that gas can flow into the casing, and installing a string of tubing inside the casing down to the production zone. Gas can then be made to flow up to the surface through a production chamber, which may be either the tubing or the annulus between the tubing and the casing. The gas flowing up the production chamber is conveyed through an intake pipeline running from the wellhead to the suction inlet of a wellhead compressor. The compressed gas discharged from the compressor is then conveyed through another pipeline to a gas processing facility and sales facility as appropriate.  
         [0003]     When natural gas is flowing up a well, formation liquids will tend to be entrained in the gas stream, in the form of small droplets. As long as the gas is flowing upward at or above a critical velocity (the value of which depends on various well-specific factors), the droplets will be lifted along with the gas to the wellhead. In this situation, the gas velocity provides the means for lifting the liquids, and the well is said to be producing by “velocity-induced flow”. Because liquids in the gas stream can cause internal damage to most gas compressors, a gas-liquid separator is provided in the intake pipeline to remove liquids from the gas stream before entering the compressor. The liquids may be pumped from the separator and reintroduced into the gas flow at a point downstream of the compressor, for eventual separation at the gas processing facility. Much more commonly, however, the liquids are collected in a tank on the well site.  
         [0004]     In order to optimize total volumes and rates of gas recovery from a gas reservoir, the bottomhole flowing pressure should be kept as low as possible. The theoretically ideal case would be to have a negative bottomhole flowing pressure so as to facilitate 100% gas recovery from the reservoir, resulting in a final reservoir pressure of zero. In order to reduce the bottomhole pressure to a negative value, or to a very low positive value, it would be necessary to have a negative flowing pressure (i.e., less than atmospheric pressure) in the intake pipeline. This can be readily accomplished using well-known technology; i.e., by providing a wellhead compressor of sufficient power.  
         [0005]     However, negative pressure in a natural gas pipeline would present an inherent problem, because any leak in the line (e.g., at pipeline joints) would allow the entry of air into the pipeline, because air would naturally flow to the area of lower pressure. This would create a risk of explosion should the air/gas mixture be exposed to a source of ignition. In addition to the explosion risk, entry of air into the pipeline also creates or increases the risk of corrosion inside the pipeline. For these reasons, the pressure in the intake pipeline is typically maintained at a positive level (i.e., higher than atmospheric). Therefore, in the event of a leak in the intake pipeline, gas in the pipeline will escape into the atmosphere, rather than air entering the pipeline. The explosion and corrosion risks are thus minimized or eliminated, but in a way that effectively limits ultimate recovery of gas reserves from the well.  
         [0006]     One way of minimizing or eliminating the explosion and corrosion risks, while facilitating the use of negative pressures in the intake pipeline, would be to provide an oxygen sensor in association with the pipeline. The oxygen sensor would be adapted to detect the presence of oxygen inside the pipeline, and to shut down the compressor immediately upon detection of oxygen. This system thus would more safely facilitate the use of compressor suction to induce negative pressures in the intake pipeline and, therefore, to induce negative or low positive bottomhole flowing pressures. However, this system has an inherent drawback in that its effectiveness would rely on the proper functioning of the oxygen sensor. If the sensor malfunctions, and if the malfunction is not detected and remedied in timely fashion, the risk of explosion and/or corrosion will become manifest once again. This fact highlights an even more significant drawback in that this system would not prevent the influx of air into the pipeline in the first place, but is merely directed to mitigation in the event of that undesirable event.  
         [0007]     For the foregoing reasons, there is a need for an improved method and apparatus for minimizing and protecting against the risk of explosion arising from the influx of air into a pipeline carrying a combustible gas such as natural gas under negative pressure. There is a particular need for such methods and apparatus that do not require or rely on the use of oxygen sensors or other instruments or devices that are prone to malfunction. Even more particularly, there is a need for such methods and apparatus that prevent the influx of air into the pipeline in the first place. The present invention is directed to these needs.  
       BRIEF DESCRIPTION OF THE INVENTION  
       [0008]     In general terms, the present invention provides a method and apparatus whereby the intake pipeline running between the production chamber of a natural gas well and the suction inlet of an associated wellhead compressor is completely enclosed, in vapour-tight fashion, within a jacket of natural gas under positive pressure (i.e., higher than atmospheric). Being enclosed inside this “positive pressure jacket”, the intake pipeline is not exposed to the atmosphere at any point. This allows gas to be drawn into the compressor through the intake pipeline under a negative pressure, without risk of air entering the intake pipeline should a leak occur in the pipeline. If such a leak occurs, there would merely be a harmless transfer of gas from the positive pressure jacket into the intake pipeline. If a leak occurs in the positive pressure jacket, gas therefrom would escape into the atmosphere, and entry of air into the positive pressure jacket would be impossible.  
         [0009]     Accordingly, in one aspect the present invention is a positive pressure gas jacket apparatus for use in association with a natural gas well facility, said well facility comprising: 
        (a) a wellbore extending from ground surface into a subsurface gas production zone;     (b) a wellhead apparatus at the top of the wellbore;     (c) a tubing string extending from the wellhead into the wellbore, for conveying gas from the production zone, said tubing string and wellbore defining an annulus;     (d) an upstream pipeline in fluid communication with a production chamber selected from the tubing and the annulus, and connecting to the suction manifold of a gas compressor; and     (e) a downstream pipeline extending from the discharge manifold of the compressor: 
 
 said apparatus comprising: 
    (f) a vapour-tight enclosure defining an internal chamber surrounding the upstream pipeline; and     (g) a gas recirculation pipeline extending between a selected point on the downstream pipeline and a selected point on the vapour-tight enclosure, such that the gas recirculation pipeline is in fluid communication with both the downstream pipeline and the internal chamber of the vapour-tight enclosure; 
 
 characterized in that the upstream pipeline will be completely enveloped by pressurized natural gas introduced into the internal chamber from the downstream pipeline via the recirculation pipeline. 
       
 
         [0017]     In a second aspect, the invention is a method of preventing air leaks into the upstream pipeline of a natural gas well facility as described above, the method comprising the steps of: 
        (f) providing a vapour-tight enclosure defining an internal chamber surrounding the upstream pipeline; and     (g) providing a gas recirculation pipeline extending between a selected point on the downstream pipeline and a selected point on the vapour-tight enclosure, such that the gas recirculation pipeline is in fluid communication with both the downstream pipeline and the internal chamber of the vapour-tight enclosure; 
 
 said method being characterized in that the upstream pipeline will be completely enveloped by pressurized natural gas introduced into the internal chamber from the downstream pipeline via the recirculation pipeline. 
       
 
         [0020]     In preferred embodiments of the apparatus and the method, a throttling valve is provided in the recirculation pipeline, for regulating the flow of gas from the downstream pipeline into the recirculation pipeline.  
         [0021]     Also in preferred embodiments, a pressure regulator valve (PRV) is disposed between the internal chamber of the vapour-tight enclosure and a well injection chamber selected from the tubing and the annulus, said injection chamber not being the production chamber. The PRV is adapted to prevent gas pressure in the internal chamber from exceeding a selected pre-set value, by allowing gas from the internal chamber to enter the well injection chamber when the internal chamber pressure exceeds the pre-set value.  
         [0022]     The vapour-tight enclosure is preferably of welded steel construction. However, other materials and known fabrication methods may be used without departing from the scope of the invention.  
         [0023]     In the preferred embodiment, the positive pressure gas jacket apparatus also comprises a gas-liquid separator apparatus connected into the upstream pipeline for separating liquids out of raw gas from the well, with a liquid discharge line for removing separated liquids, and with the internal chamber of the vapour-tight enclosure surrounding the separator apparatus as well as the upstream pipeline. In accordance with this embodiment, pressurized gas introduced into the internal chamber from the downstream pipeline via the recirculation pipeline will completely envelope both the separator apparatus and the discharge line.  
         [0024]     In a particularly preferred embodiment, the separator apparatus comprises a separator vessel, a blow case, and a liquid transfer line for carrying separated liquids from the separator vessel to the blow case. The blow case is of a type well known in the art, being a pressure vessel for retaining the separated liquids under positive pressure. The liquid discharge line connects to the blow case and extends therefrom through the vapour-tight enclosure for conveying liquids from the blow case under positive pressure to a liquid disposal point (which may be a storage tank, or alternatively may be a connection to the downstream pipeline). Since the liquids leave the blow case under positive pressure, it is not necessary for the vapour-tight enclosure to enclose any portion of the liquid discharge line.  
         [0025]     In an alternative embodiment not having a blow case, liquids removed by the separator apparatus are discharged into the liquid discharge line under negative pressure, and the liquid discharge line connects to a vacuum pump, which in turn discharges the liquids under positive pressure into a liquid return line. The internal chamber of the vapour-tight enclosure surrounds the liquid discharge line as well as the separator apparatus and the upstream pipeline, such that pressurized gas introduced into the internal chamber from the downstream pipeline via the recirculation pipeline will completely envelope the upstream pipeline, the separator apparatus, and the discharge line. 
     
    
     BRIEF DESCRIPTION OF THE DRAWINGS  
       [0026]     Embodiments of the invention will now be described with reference to the accompanying figures, in which numerical references denote like parts, and in which:  
         [0027]      FIG. 1  is a schematic diagram of a well producing natural gas in accordance with prior art methods and apparatus.  
         [0028]      FIG. 2  is a schematic diagram of a well producing natural gas in accordance with a preferred embodiment of the method and apparatus of the present invention.  
         [0029]      FIG. 3  is a schematic diagram of a well producing natural gas in accordance with an alternative embodiment of the method and apparatus of the invention.  
         [0030]      FIG. 4  is a partial cutaway schematic diagram of a separator having a positive pressure gas jacket in accordance with a preferred embodiment of the invention.  
         [0031]      FIG. 5  is a schematic diagram of a gas well producing natural gas using a prior art gas injection system.  
         [0032]      FIG. 6  is a schematic diagram of the gas well shown in  FIG. 5 , producing natural gas using a prior art gas injection system, modified to incorporate the positive pressure jacket of the present invention. 
     
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT  
       [0033]     The present invention will be best understood after first reviewing conventional methods and apparatus for carrying natural gas from a well to a compressor.  FIG. 1  schematically illustrates a typical natural gas well W configured in accordance with prior art methods and apparatus. The well W penetrates a subsurface formation F containing natural gas (typically along with water and crude oil in some proportions). The well W is lined with a casing  20  which has a number of perforations conceptually illustrated by short lines  22  within a production zone (generally corresponding to the portion of the well penetrating the formation F). As conceptually indicated by arrows  24 , formation fluids including gas, oil, and water may flow into the well through the perforations  22 . A string of tubing  30  extends inside the casing  20 , terminating at a point within the production zone. The bottom end of the tubing  30  is open such that fluids in the wellbore may freely enter the tubing  30 . An annulus  32  is formed between the tubing  30  and the casing  20 . The upper end of the tubing  30  runs into a surface termination apparatus or “wellhead” (not illustrated), of which various types are known in the field of gas wells.  
         [0034]     It should be noted that, to facilitate illustration and understanding of the invention, the Figures are not drawn to scale. The diameter of the casing  20  is commonly in the range of 4.5 to 7 inches (114 to 178 mm), and the diameter of the tubing  30  is commonly in the range of 2.375 to 3.5 inches (60 to 89 mm), while the well W typically penetrates hundreds or thousands of feet into the ground. It should also be noted that except where indicated otherwise, the arrows in the Figures denote the direction of flow within various components of the apparatus.  
         [0035]     In the well configuration shown in  FIG. 1 , the tubing  30  serves as the production chamber to carry gas from the well W, under positive pressure, via the wellhead (not shown) to a production pipeline  40  having an upstream section  40 U which carries the gas through a gas-liquid separator  70  to the suction manifold  42 S of a gas compressor  42 . The separator  70  divides the upstream pipeline into section  40 U′ on the wellhead side of the separator, and section  40 U″ on the compressor side of the separator  70 . The production pipeline  40  also has a downstream section  40 D which connects at one end to the discharge manifold  42 D of the compressor  42  and continues therefrom to a gas processing facility (not shown). As schematically indicated, liquids  72  separated from the gas flowing in the intake pipeline  40 U′ will accumulate in a lower section of the separator  70 . In the usual case, the liquids  72  flow from the separator  70  to a storage tank  80  on the well site.  
         [0036]     The present invention may be best understood from reference to  FIG. 2 . The invention provides for production of gas under negative pressure, in which case the liquids  72  removed from the gas stream by the separator  70  will also be under negative pressure, and for this reason a vacuum pump  74  is provided as shown. The liquids  72  flow under negative pressure through a pump inlet line  78  to the pump  74 , which pumps the liquids  72 , now under positive pressure, through a liquid return line  76  into the downstream section  40 D of production pipeline  40  at a point Z downstream of the compressor  42 . Alternatively, the liquids  72  may be pumped to an on-site storage tank  80 .  
         [0037]     As illustrated in  FIG. 2 , the upstream pipeline sections  40 U′ and  40 U″, the separator  70 , and the pump inlet line  78  are fully enclosed by a vapour-tight positive pressure jacket  50  that defines a continuous internal chamber  52 . The positive pressure jacket  50  will typically be constructed of welded steel. However, suitable and well-known alternative materials may be used without departing from the fundamental concept and scope of the present invention.  
         [0038]     A gas recirculation pipeline  60  extends between, and is in fluid communication with, the downstream section  40 D of production pipeline  40  (at point X located between the compressor  42  and point Z) and a selected pressure connection point Y on the positive pressure jacket  50 . As shown in  FIG. 2 , pressure connection point Y may be located in upstream pipeline section  40 U″ between the compressor  42  and the separator  70 . However, this is not essential; pressure connection point Y may be at any convenient location on the positive pressure jacket  50 —such as, for example, on the portion of the positive pressure jacket  50  surrounding the separator  70 , as schematically indicated by broken lines (marked  61 ), which depict an optional alternative routing of the recirculation pipeline  60 .  
         [0039]     By means of the recirculation pipeline  60 , a portion of the gas discharged from the discharge manifold  42 D of the compressor  42  may be diverted into the positive pressure jacket  50 , such that the upstream pipeline sections  40 U′ and  40 U″, the separator  70 , and the pump inlet line  78  are entirely enclosed by a “blanket” of gas under positive pressure.  
         [0040]     The positive pressure jacket  50  thus enshrouds all components of the apparatus containing combustible fluids under negative pressure between the wellhead and the suction manifold  42 S of compressor  42  with a blanket of gas under positive pressure, thereby preventing the entry of air into the combustible fluids present in any of those components.  
         [0041]     In the preferred embodiment, the positive pressure jacket  50  also encloses any portions of the wellhead containing gas under negative pressure.  
         [0042]     The embodiment shown in  FIG. 2  provides for what may be termed a “static” positive pressure blanket, as the gas inside the positive pressure jacket  50  will be essentially stationary. In an alternative embodiment of the invention, illustrated in  FIG. 3 , the internal chamber  52  of the positive pressure jacket  50  is in fluid communication with the annulus  32  of the well W, such that gas from the internal chamber  52  of the positive pressure jacket  50  can be injected into the annulus  32 . As shown schematically in  FIG. 3 , a pressure regulator valve  54  is provided to regulate the gas pressure inside the positive pressure jacket  50 . The pressure regulator valve  54  may be set such that it will open, thus allowing gas to enter the annulus  32 , only when the gas pressure in the internal chamber  52  of the positive pressure jacket  50  is above a selected value. Under either static conditions (as in  FIG. 2 ) or gas injection conditions (as in  FIG. 3 ), internal chamber pressures in the approximate range of 40 to 50 pounds per square inch (275 to 345 kPa) are considered desirable. However, higher or lower pressures may be used without departing from the concept and principles of the present invention.  
         [0043]     As schematically illustrated in  FIG. 3 , a throttling valve (or “choke”)  62  optionally may be provided in association with the recirculation pipeline  60 , to regulate the flow of gas from the downstream section  40 D of production pipeline  40  into the recirculation pipeline  60  and thence into the internal chamber  52  of the positive pressure jacket  50  and ultimately into the well W.  
         [0044]      FIG. 4  schematically illustrates a preferred construction of the separator  70  and the corresponding section of the positive pressure jacket  50  in accordance with the present invention. In this embodiment, the separator  70  comprises two main components, a vertical separator  90  and a blow case  100 , the construction and operation of which are in accordance with well known technology. Upstream pipeline section  40 U′ delivers raw well gas under negative pressure to the separator. Upstream pipeline section  40 U″ delivers dry gas from the separator  70  to the suction manifold  42 S of the compressor  42 . The vertical separator  90  and blow case  100  are enclosed within a separator jacket  55  forming part of the overall positive pressure jacket  50 . Injection pipeline  60 , carrying gas under pressure from the downstream pipeline  40 D, is connected to the positive pressure jacket  50  at pressure connection point Y (which in the embodiment shown in  FIG. 4  is located on separator jacket  55 , but may be located elsewhere on the positive pressure jacket  50  as previously mentioned). Regardless of the location of pressure connection point Y, gas under pressure is introduced into the internal chamber  52  of the positive pressure jacket  50 , such that all system components carrying raw gas from the well W under negative pressure will be surrounded by gas under positive pressure.  
         [0045]     Liquids  72  removed from the gas are discharged from the vertical separator  90  at liquid outlet  96  through liquid transfer line  98 , which in turn carries the liquids  72  to the blow case  100  through blow case inlet port  102 . The blow case  100  accumulates separated liquids under positive pressure. Liquid return line  76  connects to the blow case  100  at blow case discharge port  104 . A check valve  106  prevents liquids from being discharged from the blow case  100  unless the pressure in the blow case exceeds a pre-set value. In this embodiment, there is no need for a pump  74  (as in the embodiments shown in  FIG. 2  and  FIG. 3 ) and therefore no pump inlet line  78 . The flow in the liquid return line  76  will always be under positive pressure as it exits the separator jacket  55 .  
         [0046]     Alternative methods of constructing the positive pressure jacket  50  around the separator  70 , using known fabrication methods and materials, will be readily apparent to persons skilled in the art, without departing from the principles of the invention.  
         [0047]     The method and apparatus of the present invention can be particularly advantageous when used in conjunction with gas wells in which gas injection is used to enhance recovery of gas from the formation F. Gas injection provides this benefit by further reducing bottomhole pressures in the well W. Formation pressures in virgin gas reservoirs tend to be relatively high. Therefore, upon initial completion of a well, the gas will commonly rise naturally to the surface provided that the characteristics of the reservoir and the wellbore are suitable to produce stable flow (meaning that the gas velocity at all locations in the production chamber remains equal to or greater than the critical velocity—in other words, velocity-induced flow).  
         [0048]     However, as wells penetrate the reservoir and gas reserves are depleted, the formation pressure drops continuously, inevitably to a level too low to induce gas velocities high enough to sustain stable flow. Therefore, all flowing gas wells producing from reservoirs with depleting formation pressure eventually become unstable. Once the gas velocity has become too low to lift liquids, the liquids accumulate in the wellbore, and the well is said to be “liquid loaded”. This accumulation of liquids results in increased bottomhole flowing pressures and reduced gas recoveries. Injection of recirculated gas can effectively prevent or alleviate liquid loading, by increasing the upward velocity of the gas stream in the production chamber so as to maintain a gas velocity at or above the critical velocity for the well in question, thus maintaining velocity-induced flow. Methods and apparatus for gas injection for this purpose are described in the present Applicant&#39;s Canadian Patent Application No. 2,242,745, filed on Apr. 9, 2003 and corresponding International Application No. PCT/CA2004/000478, filed on Mar. 30, 2004.  
         [0049]      FIG. 5  illustrates a gas well producing natural gas using an embodiment of the gas injection system disclosed in PCT/CA2004/000478. In the well configuration shown in  FIG. 5 , the tubing  30  serves as the production chamber to carry gas from the well W to an above-ground production pipeline  40 , which has an upstream section  40 U and a downstream section  40 D. The tubing  30  connects in fluid communication with one end of the upstream section  40 U (via wellhead apparatus, not shown), and the other end of the upstream section  40 U is connected to the suction manifold  42 S of a gas compressor  42 . The downstream section  40 D of the production pipeline  40  connects at one end to the discharge manifold  42 D of the compressor  42  and continues therefrom to a gas processing facility (not shown). A gas injection pipeline  16 , for diverting production gas from the production pipeline  40  for injection into the injection chamber (i.e., the annulus  32 , in  FIG. 5 ), is connected at one end to the downstream section  40 D of the production pipeline  40  at a point Q, and at its other end to the top of the injection chamber. Also provided is a throttling valve (or “choke”)  12 , which is operable to regulate the flow of gas from the production pipeline  40  into the injection pipeline  16  and the injection chamber.  
         [0050]     The choke  12  may be of any suitable type. In a fairly simple embodiment of the apparatus, the choke  12  may be of a manually-actuated type, which may be manually adjusted to achieve desired rates of gas injection, using trial-and-error methods as may be necessary or appropriate; with practice, a skilled well operator can develop a sufficiently practical ability to determine how the choke  12  needs to be adjusted to achieve stable gas flow in the production chamber, without actually quantifying the necessary minimum gas injection rate or the flow rate in the production chamber. Alternatively, the choke  12  may be an automatic choke; e.g., a Kimray® Model 2200 flow control valve.  
         [0051]     In the preferred embodiment, however, a flow controller  150  is provided for operating the choke  12 . Also provided is a flow meter  14  adapted to measure the rate of total gas flow up the production chamber, and to communicate that information to the flow controller  50 . The flow controller  150  may be a pneumatic controller of any suitable type; e.g., a Fisher™ Model 4194 differential pressure controller.  
         [0052]     To implement the gas injection system illustrated in  FIG. 5 , a critical gas flow rate is determined. The critical flow rate, which may be expressed in terms of either gas velocity or volumetric flow, is a parameter corresponding to the minimum velocity V cr  that must be maintained by a gas stream flowing up the production chamber (i.e., the tubing  30 , in  FIG. 5 ) in order to carry formation liquids upward with the gas stream (i.e., by velocity-induced flow). This parameter is determined in accordance with well-established methods and formulae taking into account a variety of quantifiable factors relating to the well construction and the characteristics of formation from which the well is producing. A minimum total flow rate (or “set point”) is then selected, based on the calculated critical flow rate, and flow controller  150  is set accordingly. The selected set point will preferably be somewhat higher than the calculated critical rate, in order to provide a reasonable margin of safety, but also preferably not significantly higher than the critical rate, in order to minimize friction loading in the production chamber.  
         [0053]     If the total flow rate measured by the meter  14  is less than the set point, the flow controller  150  will adjust the choke  12  to increase the gas injection rate if and as necessary to increase the total flow rate to a level at or above the set point. If the total flow rate is at or above the set point, there may be no need to adjust the choke  12 . The flow controller  50  may be adapted such that if the total gas flow is considerably higher than the set point, the flow controller  150  will adjust the choke  12  to reduce the gas injection rate, thus minimizing the amount of gas being recirculated to the well through injection, and maximizing the amount of gas available for processing and sale.  
         [0054]     In one particular embodiment of the gas injection system, the flow controller  150  has a computer with a microprocessor (conceptually illustrated by reference numeral  160 ) and a memory (conceptually illustrated by reference numeral  162 ). The flow controller  150  also has a meter communication link (conceptually illustrated by reference numeral  152 ) for receiving gas flow measurement data from the meter  14 . The meter communication link  152  may comprise a wired or wireless electronic link, and may comprise a transducer. The flow controller  150  also has a choke control link (conceptually illustrated by reference numeral  154 ), for communicating a control signal from the computer  160  to a choke control means (not shown) which actuates the choke  12  in accordance with the control signal from the computer. The choke control link  154  may comprise a mechanical linkage, and may comprise a wired or wireless electronic link.  
         [0055]     Using this embodiment of the apparatus, the set point is stored in the memory  162 . The computer  160  receives a signal from the meter  14  (via the meter communication link  152 ) corresponding to the measured total gas flow rate in the production chamber, and, using software programmed into the computer  160 , compares this value against the set point. The computer  160  then calculates a minimum injection rate at which supplementary is gas must be injected into the injection chamber, or to which the injection rate must be increased in order to keep the total flow rate at or above the set point. This calculation takes into account the current gas injection rate (which would be zero if no gas is being injected at the time). If the measured total gas flow is below the set point, the computer  160  will convey a control signal, via the choke control link  154 , to the choke control means, which in turn will adjust the choke  12  to deliver injection gas, at the calculated minimum injection rate, into the injection pipeline  16 , and thence into the injection chamber of the well (i.e., the annulus  32 , in  FIG. 1 ). If the measured total gas flow equals or exceeds the set point, no adjustment of the choke  12  will be necessary, strictly speaking.  
         [0056]     However, the computer  160  may also be programmed to reduce the injection rate if it is substantially higher than the set point, in order to minimize the amount of gas being recirculated to the well W, thus maximizing the amount of gas available for processing and sale, as well as to minimize friction loading. In fact, situations may occur in which there effectively is a “negative” gas injection rate; i.e., where rather than having gas being injected downward into the well through a selected injection chamber, gas is actually flowing to the surface through both the tubing  30  and the annulus  32 . This situation could occur when formation pressures are so great that the upward gas velocity in the selected production chamber is not only high enough to maintain a velocity-induced flow regime, but also so high that excessive friction loading develops in the production chamber. In this scenario, gas production would be optimized by producing gas up both chambers, thus reducing gas velocities and resultant friction loading (provided of course that the gas velocity—which will be naturally lower than when producing through only one chamber—remains above V cr  at all points in at least one of the chambers; i.e., so that there is stable flow in at least one chamber).  
         [0057]      FIG. 6  illustrates the well and gas injection system shown in  FIG. 5 , but modified to incorporate the positive pressure jacket of the present invention, with separator and positive pressure jacket components corresponding to those described and illustrated in connection with  FIG. 2  and  FIG. 5 . In the embodiment shown in  FIG. 6 , the recirculation pipeline  60  ties in to the injection pipeline  16 , but this is only a representative illustration of one means of providing gas under positive pressure to the internal chamber  52  of the positive pressure jacket  50 . For example, the recirculation pipeline  60  could be a separate line connecting to downstream pipeline  40 D, independent of injection pipeline  16 .  
         [0058]     Although not illustrated, it will be appreciated that the gas injection embodiments shown in  FIGS. 3, 4 , and  6  can be readily adapted for use in association with a gas well in which the annulus  32  serves as the production chamber. In that case, the upstream section  40 U of intake pipeline  40  will be in fluid communication with the annulus  32 , and the internal chamber  52  of the positive pressure jacket  50  will be in fluid communication with the production tubing  30 . Accordingly, pressurized gas diverted into the internal chamber  52  will be injected into the well W through the tubing  30 , with the same production-enhancing benefits as described previously in connection with embodiments wherein the tubing  30  serves as the production chamber.  
         [0059]     It will be readily appreciated by those skilled in the art that various modifications of the present invention may be devised without departing from the essential concept of the invention, and all such modifications are intended to be included in the scope of the claims appended hereto.  
         [0060]     In this patent document, the word “comprising” is used in its non-limiting sense to mean that items following that word are included, but items not specifically mentioned are not excluded. A reference to an element by the indefinite article “a” does not exclude the possibility that more than one of the element is present, unless the context clearly requires that there be one and only one such element.

Technology Classification (CPC): 4