Abstract:
A gas recovery system where a submersible compressor is in combination with a hydraulic motor. The hydraulic motor is actuated by a pressure differential between hydraulic power lines extending between the motor and a pressure generation means at or near the surface. Hydraulic fluid serves to actuate device components and regulate the temperature of the down hole compressor. A monitoring system evaluates, communicates, and records operation parameters so that they may be adjusted to ensure a constant volume of produced gas. The device may operate at variable speeds to accommodate changing downhole pressure conditions.

Description:
CITATION TO PRIOR APPLICATION  
       [0001]     This application claims the benefit of U.S. Provisional Application No. 60/647,068, filed Jan. 26, 2005. 
     
    
     BACKGROUND OF THE INVENTION  
       [0002]     1. Field of the Invention  
         [0003]     The present invention generally relates to a system for the recovery of gas. More specifically, the present invention relates to a system for the recovery of gas that is actuated by a hydraulic motor.  
         [0004]     2. Background Information  
         [0005]     Gas recovery devices heretofore devised and utilized are known to consist basically of familiar, expected and obvious structural configurations, notwithstanding the myriad of designs encompassed by the crowded prior art which have been developed for the fulfillment of countless objectives and requirements. While these devices may fulfill their respective, particularly claimed objectives and requirements, these devices do not disclose a gas recovery device and method of use such as Applicant&#39;s present invention.  
         [0006]     Currently, numerous “dry” gas wells located in the United States produce gas through a production casing annulus. These wells are typically less than 3000 feet deep and contain an abundance of natural gas. In addition, these wells are often able to produce gas while having relatively low down hole pressure using techniques where surface pressure is brought down to near zero. That is, common recovery techniques involve surface compression facilities that reduce surface pressure to near vacuum. By exaggerating differential pressure along the bottom side of the well bore, the surface gas is free to flow from an area of higher pressure (downhole) to an area of lower pressure (the surface brought to vacuum). Nevertheless, an appreciable amount of gas cannot be recovered using this method. Invariably, an amount of gas equal to the hydrostatic head pressure of the gas column remains in the reservoir. Obviously, the amount of unrecovered gas directly depends on the depth of the well; as such, deeper wells necessarily withhold more unrecoverable gas  
         [0007]     Gas reservoirs tend to be extremely prolific; that is, lowering the surface pressure by one pound per square inch (psig) may result in billions of cubic feet of additionally recovered natural gas. Nevertheless, known recovery techniques are unable to remove all of the natural gas contained in these wells. Most reservoirs are depletion driven, which dictates that the bottom hole pressure is constantly declining. As previously mentioned, at some point bottom hole pressure will decrease to a level where known recovery systems are unable to overcome the hydrostatic column of gas left in the well.  
         [0008]     By way of example, “abandonment bottom hole pressure” in a 2000 foot well would be ±26 psi or a gradient of 0.013 psi/foot; likewise “abandonment bottom hole pressure” in a 3000 foot well would be ±39 psi or a gradient of 0.013 psi/foot. From these numbers alone, one can easily see that a plethora of unrecovered gas remains in the well. One does not have to look hard to see that the cumulative effect is tremendous; that is, as each well is left with an appreciable amount of gas, the sum of unrecovered gas becomes increasingly significant. It is estimated by those skilled in the art that trillions of cubic feet of currently unrecoverable gas remain downhole. At an approximate price of six dollars per MCF, the economic impact is clearly a significant one.  
         [0009]     Those skilled in the art of gas recovery recognize the need to improve upon the recovery techniques known to be used. Until now, they have been met with two seemingly insurmountable obstacles: heat generated from gas compression and small diameter constraints of well bores (generally five inches or less). Each limitation, alone and in combination with one another, unduly limit the amount of gas that may be extracted from a gas reservoir. Skilled artisans have attempted to compress gas downhole in order to increase the pressure gradient between bottom hole and surface. However, increased heat associated with gas compression and higher downhole temperature typically causes compressor equipment to overheat. Also, attempts to place a compressor downhole have been hampered by the cramped dimensions of the well bore.  
         [0010]     In view of the limitations mentioned above, a great need exists for an oil recovery system that can improve upon the percentage or recovered gas contained within an individual gas reservoir. Specifically, a gas recovery system is needed that can avoid the size and temperature constraints associated with compressing gas downhole.  
       SUMMARY OF THE INVENTION  
       [0011]     The general purpose of the present invention, which will be described subsequently in greater detail, is to provide a new gas recovery system which has many of the advantages of those known in the art and many novel features that result in a new recovery system which is not anticipated, rendered obvious, suggested, or even implied by any of the known recovery systems, either alone or in any combination thereof.  
         [0012]     In satisfaction of such, the present invention provides a gas recovery device and method of use incorporating use of a small I.D. rotary vane or other type of compressor driven by a hydraulic motor. Preferably, the compressor operates at or near the bottom of a well bore along the downhole end of a coiled tubing string and is placed at producing depth. A larger coiled conduit, having smaller coiled conduits contained therein, serves to conduct compressed gas from the compressor to the surface. The two strings of coil tubing having a smaller diameter, located inside the larger coil tubing string, serve as the hydraulic fluid conduits. In its most preferred form, differential fluid pressure of each hydraulic line actuates the hydraulic motor, which drives the compressor.  
         [0013]     As previously mentioned, and to be later discussed, known compressors cannot effectively compress gas when placed downhole because of temperature related problems; specifically, compressors tend to overheat when used in such an arrangement. However, Applicant&#39;s invention solves this problem in elegant fashion. During operation, the heat generated by gas compression is absorbed by hydraulic fluid circulating along the peripheral portion of the compressor. The hydraulic fluid and compressor components are separated by a suitably rigid material that allows for effective thermal conduction. Further, when the fluid is circulating between the compressor and a pressure generating means, it may be cooled by any number of cooling means to further provide temperature regulation of the downhole compressor.  
         [0014]     Perhaps the novelty of the present invention is most easily seen in that the amount of heat produced by the compressor is directly proportional to the flow rate of circulated hydraulic fluid. In other words, as the downhole gas pressure decreases (pressure gradient between downhole and surface decreases) the compressor is subject to a heavier workload, and more energy is required to compress the gas. As such, the flow of hydraulic fluid along the compressor must increase to accommodate the faster moving motor. Naturally, the increased flow of hydraulic fluid will more effectively dissipate the additional heat produced from the harder working compressor.  
         [0015]     In its most preferred form, the present system is designed to provide a constant production rate. The production rate may be selected by the system user and evaluated and maintained by a control combination located at or near the surface. For instance, upon startup, the pressure deferential between the compressor inlet and outlet (or suction and discharge pressure) is at its lowest. This occurs when downhole gas pressure is at its highest and generally results in very good compressor efficiency. As the compressor runs, downhole pressure decreases, the compressor inlet and compressor outlet pressure differential increases, and more energy is required to compress the gas to maintain an established production rate. However, the motor (and likewise the compressor) variably operates to account for changing downhole conditions while maintaining constant production volume at the surface.  
         [0016]     With known recovery devices (i.e., those driven by electrical means) motor speed remains constant and cannot be sufficiently varied to make up for varying pressure loads on the compressor. As such, production levels necessarily decline over time as the compressor runs. With an electrically driven compressor, production level variations often overload production facilities and pipelines, cause incorrect sales gas measurement, and create “bottlenecks” in transmission gas lines. However, the hydraulically driven gas compressor of the present invention can maintain a constant production rate by varying the flow rate of hydraulic fluid. It is envisioned that a variable speed electric motor would power the surface hydraulic pump to accomplish this goal. 
     
    
     BRIEF DESCRIPTION OF THE DRAWINGS  
       [0017]     Applicant&#39;s invention may be further understood from a description of the accompanying drawings, wherein unless otherwise specified, like referenced numerals are intended to depict like components in the various views.  
         [0018]      FIG. 1  is a cross section view of the preferred embodiment of the hydraulically driven gas recovery device of the present invention.  
         [0019]      FIG. 2  is a flow chart type diagram of the preferred embodiment of the present invention. 
     
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT  
       [0020]     Referring to  FIG. 1 , the device of the present invention is generally designated by reference numeral  10 . Device  10  is envisioned as being most beneficially used in the context of recovering natural gas from underground reservoirs. As such, device  10  is typically placed within a gas recovery production casing, which is generally designated by reference numeral  12 .  
         [0021]     Device  10  is characterized by hydraulic motor  14  located at the downhole side of a submersible compressor  16 , which extends from production tubing  30 . Hydraulic motor  14 , in the preferred embodiment, is of a dimension suitable for placement within a standard sized gas reservoir (usually of a diameter of five inches or less) and preferably of a variable-speed type hydraulic motor actuated by differential fluid pressure. As will be later discussed, use of hydraulic motor  14 , alone and in combination with other components, imparts several novel attributes to the device of the present invention.  
         [0022]     In the most preferred embodiment, hydraulic motor  14  is driven by hydraulic fluid circulating through hydraulic power line high side  18  and hydraulic power line low side  20 . Each hydraulic line runs along the length of production tube  30  in adjacent fashion and extends along the length of submersible compressor  16  where each is positioned between inner compressor housing  60  and outer compressor housing  32 . Inner compressor housing  60  substantially encloses inner components of compressor  16  (i.e., rotary compression vanes). Preferably, inner compressor housing  60  is of a suitably strong material that allows efficient thermal conduction between compressor  16  components and power lines  18  and  20 . Outer compressor housing  32  surrounds a substantial portion of submersible compressor  16 , inner compressor housing  60 , and hydraulic power lines  18  and  20  and is meant to protect and hold each in relation to one another.  
         [0023]     The configuration of hydraulic power lines  18  and  20  in relation to compressor  16  is largely responsible for the unique operation of device  10 . Hydraulic fluid serves to actuate, and regulate the temperature of, system components. During operation, hydraulic fluid circulating through each power line effectively regulates the temperature of compressor  16  as compressor  16  compresses fluid taken in through inlet  26 . More specifically, the relatively cool hydraulic fluid serves to keep the component parts of compressor  16  from overheating during operation. Importantly, the amount of circulating hydraulic fluid is directly proportional to the operation speed of both hydraulic motor  14  and compressor  16 . Therefore, as the operation speed of compressor  16  increases (and the higher its operating temperature would become) so does the speed at which hydraulic fluid circulates through each power line. This direct relationship between compressor operating speed and hydraulic fluid circulation speed provides for an excellent temperature regulation mechanism. As such, the device of the present invention is able to avoid the constraints associated with known devices.  
         [0024]     At or near the surface, hydraulic power line  18  and hydraulic power line  20  are in combination with some power fluid circulating means  44  as known in the art. Power fluid circulation means  44  generates fluid pressure and flow for actuating motor  14 . At its downhole end, hydraulic line  18  terminates at hydraulic motor  14  at high side inlet  34 , and at its downhole end, hydraulic line  20  terminates at hydraulic motor  14  at low side inlet  36 . Hydraulic motor  14  is actuated by a pressure differential between hydraulic power line high side  18  and hydraulic power line low side  20 . Importantly, as the flow rate is changed, the speed of hydraulic motor  14  is changed. The particular hydraulic mechanism responsible for the actuation of hydraulic motor  14  is not critical; certainly, other suitable means for actuating motor  14  will be apparent to those skilled in the art.  
         [0025]     Hydraulic motor  14  is in combination with submersible compressor  16  such that actuation of motor  14  causes actuation of compressor  16 . As mentioned, in the preferred embodiment, submersible compressor  16  is a centrifugal rotary vane type pump as known in the art. These types of pumps are well known in the art; however, other useful embodiments are envisioned (and certainly will be apparent to those skilled in the art) where submersible compressor  16  is of some other type of pump. For example, other embodiments are envisioned where compressor  16  is a turbine pump or volute pump as known in the art. The compressor would probably have to be multi-staged to accomplish optimal compression due to diameter constraints.  
         [0026]     As such, referring to  FIG. 1 , hydraulic motor  14  is shown in combination with a centrifugal rotary vane type submersible compressor  16 . Actuation of motor  14  causes rotation of a central compressor drive shaft  22 . Drive shaft  22  is centrally aligned along submersible compressor  16  and extends along a substantial length thereof. While not necessary for operation, compressor  16  is preferably a multistage compressor. A multi stage compressor  16  is preferred; as such, it is thought to be most useful for providing sufficient compression of the gas while having a sufficiently small diameter (preferably five inches or less).  
         [0027]     During operation, a first stage compression occurs as gas taken in through inlet  26  is initially compressed as rotating element  40  (preferably an impeller) rotates within housing  60 . Gas is led to the center of rotating element  40  and is set into rotation by rotary vanes  38 . By virtue of centrifugal force, the gas is pressed from rotating element  40  and thrown from the rim or periphery of rotating element  40  with a considerable velocity and pressure. In this particular embodiment, when the rotor spins, centrifugal force pushes the vanes out to touch the casing, where they trap and propel fluid. Sometimes springs also push the vanes outward. When the vanes reach the return side they are pushed back into the rotor by the casing. Fluid escapes through a channel or groove cut into the casing.  
         [0028]     As previously mentioned, the benefits achieved by the present system are not necessarily dependent on the specific type of compressor used. Particularly useful embodiments are envisioned where compressor  16  is a turbine compressor as known in the art. Where, during operation, recovered gas goes from intake to discharge (in just under one revolution) as it circulates along the compressor peripheral. Each time the gas passes the turbine blades it gains additional pressure. This embodiment is thought to be particularly efficient in the context of relatively low flow rates. Other embodiments are currently envisioned where compressor  16  is a volute compressor as known in the art.  
         [0029]     Housing  60 , which closely surrounds rotating element  40 , has a volute shaped passage of increasing area, which collects gas leaving rotating element  40 , and converts a portion of its velocity energy into additional pressure energy. This housing passage leads to a first discharge area where the initially compressed gas is again forced through the process described above one or more times. Useful embodiments are envisioned where compressor  16  has a balanced configuration where there are two inlet and two outlet ports. Such a configuration is thought to be particularly useful in eliminating any considerable unbalanced force on the drive shaft, that may occur where the high-pressure, outlet area is all on one side. Also, as one or more “compression chambers” may be stacked upon one another, each chamber may be staggered so that the compressor remains balanced during operation.  
         [0030]     By virtue of the novel configuration of the present invention typical problems related to high temperature and size constraints are avoided. Hydraulic fluid circulating along the outside of compressor  16  serves to regulate the temperature of compressor  16  during downhole operation. Also, by having a series of rotating elements and rotary vanes  38  and discharge area combinations “stacked” upon one another, compressor  16  is able to achieve sufficient compression while being of a sufficiently small diameter to be placed in a typical production casing  12 . These features, alone and in combination with one another, are not available with known systems.  
         [0031]     Use of hydraulic motor  14  provides other novel benefits as well. As gas is recovered, the level of gas remaining in the well decreases; as such, the pressure gradient between downhole and surface decreases. When these compressors are driven by AC electric motors, as all such known compressors in this context are, production falls off with a decrease in production efficiency associated with the declining gas suction pressures. This decrease is rooted in the constraint that the electric motor maintains constant speed and power. It cannot accelerate or increase power to compensate for decreased downhole pressure. However, Applicant&#39;s invention avoids this limitation. The speed of hydraulic motor  14  may easily be increased in corresponding fashion to maintain a constant production volume.  
         [0032]     Efficient operation of the present device is bolstered by complimentary components put in place to evaluate operation of the system and the produced gas. That is, in the preferred embodiment, controller means  50  serves to evaluate the operation of the device against a series of selected operational parameters. Preferably, although not exclusively, controller means  50  would work from differential amps to motor  14  and compressor  16 . In this fashion, compressor  16  may start on a preset “slow power” setting and gradually ramp up to desired production parameters. As the fluid level descends in the well bore, additional power is necessary to produce the same volume of fluid (due to the decrease in pressure differential at surface and downhole). Necessary power (probably measured in amps load) should correlate to producing fluid level and production volumes. Finally, production volumes can be measured by measurement means  42 . Measurement means  42  may be any of several types as known in the art, such as a differential flow meter produced by companies such as HALIBURTON and EDI. General operation of the preferred embodiment involves information received at measurement means  42  being sent to controller means  50 . Controller means  50  may then carry out any number of functions (i.e., evaluate, compare, and record production volume and other parameters; adjust operation of hydraulic fluid circulating means  44 ) to better manage the operation of the device.  
         [0033]     Although the invention has been described with reference to specific embodiments, this description is not meant to be construed in a limited sense. Various modifications of the disclosed embodiments, as well as alternative embodiments of the inventions will become apparent to persons skilled in the art upon the reference to the description of the invention. It is, therefore, contemplated that the appended claims will cover such modifications that fall within the scope of the invention.