Patent Grant
11952874
The disclosure relates generally to subterranean well development operations and in particular, to electrical submersible pump assemblies with canned motors.
One method of producing hydrocarbon fluid from a well bore that lacks sufficient internal pressure for natural production is to utilize an artificial lift method such as an electrical submersible pump. A string of tubing or pipe known as a production string suspends the submersible pumping device near the bottom of the well bore proximate to the producing formation. The submersible pumping device is operable to retrieve production zone fluid, impart a higher pressure into the fluid and discharge the pressurized production zone fluid into production tubing. Pressurized well bore fluid rises towards the surface motivated by difference in pressure. Electrical submersible pumps can be useful, for example, in high gas to oil ratio operations and in aged fields where there is a loss of energy and the hydrocarbons can no longer reach the surface naturally.
Some current electrical submersible pump assemblies have an electric motor with a rotor and stator. In such motors, corrosive fluids, such as hydrogen sulfide, may enter the space between the rotor and the stator damaging the stator components.
Some current motors of electric submersible pump systems utilize seals to prevent wellbore and other fluids from entering the stator body. However, such seals are prone to leaks during handling of the electrical submersible pump system, in particular when the motor has a length that is significantly longer than the diameter, enabling the motor to bend and otherwise deform during handling. A current common cause of failure of electric submersible pump systems is the entry of the wellbore fluid into the electric motor, which causes a short to earth.
Embodiments disclosed herein provide systems and methods for hermetically isolating a stator body from wellbore fluids. Embodiments of this disclosure further provide a hydrophobic fluid located within the rotor cavity to lubricate and cool the rotor. Because the rotor stator body is hermetically sealed, the hydrophobic fluid will not come into contact with the stator windings and does not need to be a traditional dielectric oil. A membrane within the rotor cavity can bind components of the wellbore fluids.
In an embodiment of this disclosure a system for producing hydrocarbons from a subterranean well includes an electrical submersible pump assembly with a motor. The motor has a motor housing, the motor housing being an elongated member. A stator is located within the motor housing. The stator has a stator body with an interior cavity extending along a central axis of the stator. A rotor assembly is located within the interior cavity of the stator. The rotor assembly includes a rotor shaft, a rotor member, and an intermediate rotor bearing assembly. The rotor member and the intermediate rotor bearing assembly circumscribe the rotor shaft. The rotor shaft is an elongated member that extends along the central axis of the stator. A liner is located along an interior surface of the interior cavity. The liner is a thin walled member that is secured to the motor housing and seals the stator body from a wellbore fluid. A rotor cavity is located within an inner bore of the liner. A membrane is located within the liner. The membrane is formed of a material operable to bind a component of the wellbore fluid. A hydrophobic fluid is circulating within the rotor cavity.
In alternate embodiments, the membrane can be operable to bind a water of the wellbore fluid. In other alternate embodiments, the membrane can be operable to bind a crude oil of the wellbore fluid. The hydrophobic fluid can include a demulsifier. Alternately, the hydrophobic fluid can have a density that is greater than a density of the wellbore fluid. The hydrophobic fluid can alternately include magnetic particles in dielectric oil. The magnetic particles can include beads formed of a magnetic material that have a dimension of no more than ten micrometers, encapsulated within a polymer.
In other alternate embodiments, the hydrophobic fluid can include a performance improving additive, the performance improving additive operable to increase a thermal conductivity of the hydrophobic fluid. Alternately, the hydrophobic fluid can include a performance improving additive operable to increase an electrical breakdown strength of the hydrophobic fluid.
In yet other alternate embodiments, the liner can be welded at an uphole end of the motor and can be welded at a downhole end of the motor. The motor can have an axial length in a range of 0.050 to 10 meters and has an outer diameter in a range of 0.025 to 1 meters.
In an alternate embodiment of this disclosure, a method for producing hydrocarbons from a subterranean well includes providing an electrical submersible pump assembly with a motor, a seal section, and a pump. The motor has a motor housing, the motor housing being an elongated member. A stator is located within the motor housing. The stator has a stator body with an interior cavity extending along a central axis of the stator. A rotor assembly is located within the interior cavity of the stator. The rotor assembly includes a rotor shaft, a rotor member, and an intermediate rotor bearing assembly. The rotor member and the intermediate rotor bearing assembly circumscribe the rotor shaft. The rotor shaft is an elongated member that extends along the central axis of the stator. A liner is located along an interior surface of the interior cavity. The liner is a thin walled member that is secured to the motor housing and seals the stator body from a wellbore fluid. A rotor cavity is located within an inner bore of the liner. A membrane is located within the liner, the membrane formed of a material operable to bind a component of the wellbore fluid. The method further includes filling the rotor cavity with a hydrophobic fluid. The electrical submersible pump assembly is lowered into the subterranean well with a deployment string. The electrical submersible pump assembly is operated to lift production fluids in a direction out of the subterranean well and to circulate the hydrophobic fluid within the rotor cavity.
In alternate embodiments, the method can further include binding a water of the wellbore fluid with the membrane. Alternately, the method can include binding a crude oil of the wellbore fluid with the membrane. A formation of emulsions in the hydrophobic fluid can be prevented by including a demulsifier in the hydrophobic fluid. A formation of hot spots within the hydrophobic fluid can be reduced by including magnetic particles in a dielectric oil in the hydrophobic fluid. A thermal conductivity of the hydrophobic fluid can be increased by including a thermal conductivity performance improving additive in the hydrophobic fluid. An electrical breakdown strength of the hydrophobic fluid can be increased by including an electrical breakdown strength performance improving additive in the hydrophobic fluid.
In another alternate embodiment of this disclosure, a method for producing hydrocarbons from a subterranean well includes forming a rotor assembly by positioning an intermediate rotor bearing assembly and a rotor member onto a rotor shaft so that the rotor member and the intermediate rotor bearing assembly circumscribe the rotor shaft. The rotor shaft is an elongated member. The rotor assembly is pulled into an interior cavity of a stator body within a motor housing. The motor housing is an elongated member and the stator body is part of a stator. The rotor shaft extends along a central axis of the stator. A liner is located along an interior surface of the interior cavity. The liner is a thin walled member that is secured to the motor housing and seals the stator body from a wellbore fluid. A rotor cavity is located within an inner bore of the liner. A membrane is located within the liner. The membrane is formed of a material operable to bind a component of the wellbore fluid. A hydrophobic fluid is circulating within the rotor cavity. The motor housing, the stator, the rotor assembly, and the liner form a motor. The method further includes forming an electrical submersible pump assembly with the motor, a seal section, and a pump. The electrical submersible pump assembly is lowered into the subterranean well with a deployment string. The electrical submersible pump assembly is operated to lift production fluids in a direction out of the subterranean well.
So that the manner in which the above-recited features, aspects and advantages of the embodiments of this disclosure, as well as others that will become apparent, are attained and can be understood in detail, a more particular description of the disclosure briefly summarized above may be had by reference to the embodiments thereof that are illustrated in the drawings that form a part of this specification. It is to be noted, however, that the appended drawings illustrate only preferred embodiments of the disclosure and are, therefore, not to be considered limiting of the disclosure's scope, for the disclosure may admit to other equally effective embodiments.
Embodiments of the present disclosure will now be described more fully hereinafter with reference to the accompanying drawings, which illustrate embodiments of the disclosure. Systems and methods of this disclosure may, however, be embodied in many different forms and should not be construed as limited to the illustrated embodiments set forth herein. Rather, these embodiments are provided so that this disclosure will be thorough and complete, and will fully convey the scope of the disclosure to those skilled in the art. Like numbers refer to like elements throughout, and the prime notation, if used, indicates similar elements in alternative embodiments or positions.
In the following discussion, numerous specific details are set forth to provide a thorough understanding of the present disclosure. However, it will be obvious to those skilled in the art that embodiments of the present disclosure can be practiced without such specific details. Additionally, for the most part, details concerning well drilling, reservoir testing, well completion and the like have been omitted inasmuch as such details are not considered necessary to obtain a complete understanding of the present disclosure, and are considered to be within the skills of persons skilled in the relevant art.
Looking at
Pump 18 can be, for example, a rotary pump such as a centrifugal pump. Pump 18 could alternatively be a progressing cavity pump, which has a helical rotor that rotates within an elastomeric stator or other type of pump known in the art for use with an electrical submersible pump assembly. Pump 18 can consist of stages, which are made up of impellers and diffusers. The impeller, which is rotating, adds energy to the fluid to provide head and the diffuser, which is stationary, converts the kinetic energy of fluid from the impeller into potential energy (head). The pump stages can be stacked in series to form a multi-stage system that is contained within a pump housing. The sum of head generated by each individual stage is summative so that the total head developed by the multi-stage system increases linearly from the first to the last stage.
Pump 18 is located within wellbore 12 and is oriented to selectively boost the pressure of the production fluids traveling from the wellbore towards the earth's surface 14 so that production fluids can travel more efficiently to the earth's surface 14 through wellbore 12.
Motor 20 is also located within wellbore 12 and provides power to pump 18. Electrical submersible pump assembly 16 can include seal section 22. Seal section 22 can be located between pump 18 and motor 20. Seal section 22 can absorb the thrust load from pump 18, transmits power from motor 20 to pump 18, and equalizes pressure with the well while motor dielectric oil expands and contracts during operation preventing wellbore fluid from entering motor 20. Wellbore fluid can include production fluids, motor oil, treatment fluids, and other fluids utilized in subterranean development operations.
Downhole packer 24 can be located within wellbore 12 and be used to isolate the section of wellbore 12 that is downhole of downhole packer 24, from the section of wellbore 12 that contains electrical submersible pump assembly 16. Downhole packer 24 can seal around the inner diameter surface of wellbore 12 and can circumscribe stinger 26. Downhole packer 24 can be, for example, a polished bore receptacle type of packer, allowing bypass stinger 26 to sting in so that stinger 26 extends through downhole packer 24.
Electrical submersible pump assembly 16 can further include discharge 28 that is located between pump 18 and seal section 22. Discharge 28 can direct fluid that has passed through pump 18 into annular space 30 between an outer diameter surface of electrical submersible pump assembly 16 and an inner diameter of wellbore 12. Fluid within annular space 30 uphole of downhole packer 24 can be delivered to the surface by way of annular space 30.
Electrical submersible pump assembly 16 can be conventionally, cable or power coil deployed. Electrical submersible pump assembly 16 can be lowered into wellbore 12 with deployment string 38. Deployment string 38 can be, for example, coiled tubing, a wireline, or a cable. Deployment string 38 can support electrical submersible pump assembly 16 within wellbore 12. In embodiments where deployment string 38 is coiled tubing, production fluids can travel to earth's surface 14 through the coiled tubing.
As indicated by arrows 40, reservoir fluids will travel from perforations 42 that are downhole of downhole packer 24 and into stinger 26 to pass by downhole packer 24. The reservoir fluids can travel through pump 18. Discharge 28 directs the production fluid out of pump 18 and into annular space 30. The production fluid continues to travel in an uphole direction within annular space 30 past an outside diameter surface of seal section 22 and motor 20 to be produced to the surface and treated and processed using conventional methods.
Looking at
Motor 20 includes motor housing 44. Motor housing 44 is an elongated tubular member that encloses the internal components of motor 20. Motor housing 44 has inner bore 48 and can be open at both an uphole and downhole end.
Head member 50 can be connected to each of the open ends of motor housing 44. Head member 50 can be a ring shaped member. A portion of head member 50 can be located within motor housing 44 and another portion of head member 50 can protrude outside of motor housing 44. An outer diameter surface of head member 50 is connected to motor housing 44 in a manner that prevents fluids from passing into the inner bore of motor housing 44 by traveling between head member 50 and motor housing 44. In the example embodiment of
Head member 50 can include pothead 54. Pothead 54 can be an insulated electrical terminal for connecting a power cable to motor tails 56 within motor housing 44. Electrical power can then be provided to motor 20 by way of the power cable and motor tails 56.
Backup ring 58 can be connected to an inner diameter surface of head member 50. Backup ring 58 can be a ring shaped member. A portion of backup ring 58 can be located within motor housing 44 and another portion of backup ring 58 can protrude outside of motor housing 44. An outer diameter surface of backup ring 58 is connected to head member 50 in a manner that prevents fluids from passing into the inner bore of motor housing 44 by traveling between backup ring 58 and head member 50. In the example embodiment of
Stator 62 is located within motor housing 44. During operation of motor 20 stator 62 is static relative to motor housing 44. Stator 62 includes stator body 64 that is a generally ring shaped member formed of stator laminations. The stator laminations of stator body 64 can be thin steel sheets of shaped discs that are stacked together to form the axial length of stator body 64. The sheets of the lamination can be unbonded to each other or can be bonded together.
Stator body 64 can have interior cavity 66. Interior cavity 66 extends along central axis Ax of stator 62. Looking at
Looking at
Rotor assembly 72 further includes intermediate rotor bearing assembly 76. Intermediate rotor bearing assembly 76 is a ring shaped member and circumscribes rotor shaft 74. During operation of motor 20 intermediate rotor bearing assembly 76 can withstand the radial loads or forces that are perpendicular to rotor shaft 74. Intermediate rotor bearing assembly further accommodates the rotation of rotor shaft 74 relative to stator 62. Looking at
Rotor assembly 72 further includes intermediate rotor member 84. Rotor member 84 circumscribes rotor shaft 74. During operation of motor 20, rotor member 84 rotates within motor housing 44. Rotor body 86 is a generally ring shaped member. Rotor assembly 72 can be a permanent magnet rotor and have permanent magnets spaced around or within rotor body 86. In alternate embodiments, rotor assembly 72 can be an induction rotor and have rotor windings spaced around or within rotor body 86.
Outer spacer 88 and intermediate spacer 90 can maintain the position of rotor assembly 72 and intermediate rotor bearing assembly 76 within interior cavity of 66 of stator 62. Outer spacer 88 and intermediate spacer 90 can each be a single ring or can be segmented members. Outer spacer 88 is located between rotor member 84 and bearing housing 92. In the example embodiment of
Bearing housing 92 is secured to backup ring 58 with threaded member 94. Bearing housing 92 need not be sealingly secured to backup ring 58. Bearing housing 92 can have inner end 96 that engages outer spacer 88 for maintaining the position of outer spacer 88 within stator 62. An intermediate spacer 90 can be located at one or both ends of intermediate rotor bearing assembly 76 between successive rotor members 84.
End bearing 98 can circumscribe rotor shaft 74. End bearing 98 can be a radial bearing able to withstand the radial loads or forces that are perpendicular to rotor shaft 74 and accommodate the rotation of rotor shaft 74 relative to bearing housing 92.
Liner 100 is located along an interior surface of interior cavity of 66 of stator 62. Liner 100 is secured indirectly to motor housing 44 by way of head member 50 and backup ring 58. Liner 100 can be directly secured to backup ring 58. An outer diameter surface of liner 100 is connected to backup ring 58 in a manner that prevents fluids from passing into the inner bore of motor housing 44 by traveling between liner 100 and backup ring 58. In the example embodiment of
If wellbore fluids breach seal section 22, which is the barrier between the outside and inside of motor housing 44, the electrical integrity of the fluids that lubricates and cools the inside of motor 20 will be compromised and motor 20 can ultimately fail owing to an electrical short to earth. The short to earth is a particular risk at the stator windings and at pothead 54. In order to prevent the wellbore fluids from causing an electrical short to earth in the stator windings or pothead 54, stator 62 is hermetically sealed from fluids. Hermetically sealed space 104 is defined by motor housing 44, head member 50, backup ring 58, and liner 100. Because motor housing 44 is sealingly secured to head member 50, head member 50 is sealingly secured to backup ring 58, and backup ring 58 is sealingly secured to liner 100, fluids that are outside of hermetically sealed space 104 are prevented from reaching stator 62. In certain embodiments, hermetically sealed space 104 can be filled with a dielectric oil or can be solid filled to improve the heat transfer and mechanical integrity of the stator windings.
Liner 100 is an elongated thin walled member with an inner bore. As an example, liner 100 can have a wall thickness in a range of 0.25 millimeters to 1.25 millimeters. In alternate examples liner 100 can have a wall thickness of about 0.5 millimeters. Liner 100 is formed of a non-magnetic material. Liner 100 can be formed, as an example, of steel, nickel alloy, thermoplastic, or glass fiber materials. In alternate embodiments liner 100 can be formed of stainless steel 316 or Inconnel 625® (a registered mark of Special Metals Corporation). Inconnel 625® provides the benefit of reduced electrical losses.
In embodiments of this disclosure, liner 100 can have a polygonal cross section. In the example of
Decreasing the number of sides of liner 100 can improve the ability of liner 100 to prevent rotation of rotor bearing housing 78 relative to stator 62. In some currently available motor assemblies, intermediate bearing housings are prone to rotate within the stator inner diameter, which can lead to heating and failure of the bearing as well as wear of the stator laminations. Looking at
Rotor cavity 110 is located within the inner bore of liner 100. Rotor cavity 110 extends the entire length of liner 100 and is defined radially by the inner diameter surface of liner 100. Rotor cavity 110 houses rotor assembly 72. Rotor cavity 110 is sealed from hermetically sealed space 104 of motor 20 so that fluids within rotor cavity 110 do not mingle with fluids within hermetically sealed space 104. Rotor cavity 110 can therefore be filled with a fluid that is suited for interaction with rotor assembly 72, and not necessarily suited for interaction with stator 62.
As an example, rotor cavity 110 can contain a hydrophobic fluid. The hydrophobic fluid can circulate within rotor cavity 110 by the rotating action of rotor shaft 74 and rotor member 84. In certain embodiments, rotor shaft 74 can be hollow. Having a hollow rotor shaft 74 can provide improved circulation of the hydrophobic fluid within rotor cavity 110, as is further explained below.
The hydrophobic fluid can be engineered to improve the performance of motor 20. As an example, the formation of emulsions in the hydrophobic fluid. The demulsifier can be, for example, a silicone polyether. In alternate embodiments, the demulsifier can include a polyol block copolymer, an alkoxylated alkyl phenol formaldehyde resin, an epoxy resin alkoxylate, an amine-initiated polyol block copolymer, a modified silicone polyethers, or combinations of such demulsifier components.
In alternate embodiments, the hydrophobic fluid can include one or more performance improving additives. As an example, the hydrophobic fluid can include an additive that increases the thermal conductivity of the hydrophobic fluid, that increases the electrical breakdown strength of the hydrophobic fluid, or that reduces the formation of hot spots within the hydrophobic fluid.
In certain embodiments the performance improving additive can increase the thermal conductivity of the hydrophobic fluid. Such additive can increase the heat transfer capacity of the hydrophobic fluid, can improve the thermal conductivity of the hydrophobic fluid or can both increase the heat transfer capacity and the thermal conductivity of the hydrophobic fluid. Improving the thermal conductivity or the heat transfer capacity of the hydrophobic fluid will improve the ability of the hydrophobic fluid to cool motor 20. As an example, the thermal conductivity performance improving additive of the hydrophobic fluid can be carbon nanotubes or ceramic particles, such as boron nitride or titanium carbide to increase heat transfer capacity or thermal conductivity.
In certain other embodiments, the performance improving additive can increase the electrical breakdown strength of the hydrophobic fluid. As an example, nanoparticles of alumina (Aluminum Oxide Al2O3) and ferrous oxide (Fe2O3) can be used to improve dielectric breakdown strength of mineral oil.
In certain other embodiments, the performance improving additive can include magnetic particles in dielectric oil. The magnetic particles can include beads formed of a magnetic material that have a dimension of no more than ten micrometers. As an example, the beads can be iron particles that have a dimension of a micrometer or less. In an example embodiment, the iron particles can have a dimension of one to one hundred nanometers.
In certain embodiments, the magnetic particles can be encapsulated within a polymer. For example, Poly Ethyl Methacrylate (PEMA) can be used to encapsulate nanoparticles of magnetic materials. Silica (SiO2) and polystyrene can also be used to encapsulate magnetic nanoparticles. The use of the polymer as an encapsulation material can prevent agglomeration of the magnetic particles, which would reduce or eliminate the benefits of adding magnetic particles to the hydrophobic fluid. Adding magnetic particles that are not encapsulated within a polymer may increase the electrical conductivity of the dielectric oil, and therefore decrease the breakdown strength of the hydrophobic fluid.
The magnetic particles can be dispersed within the dielectric oil. The dispersed magnetic particles can increase the circulation of the dielectric oil in regions within rotor cavity 110 with a changing magnetic field. This prevents the formation of hot spots as regions with a high magnetic field as the particles move through these hot spots.
The hydrophobic fluid can, in certain embodiments, have a density that is greater than a density of the wellbore fluid. Having the hydrophobic fluid with a density that is greater than the density of the wellbore fluid will prevent the wellbore fluid from entering motor 20 irrespective of the orientation of electrical submersible pump assembly 16. As an example, in embodiments where electrical submersible pump assembly 16 are located within a vertical or deviated well, the hydrophobic fluid having a density that is greater than the density of the wellbore fluid will not allow for the wellbore fluid to displace the hydrophobic fluid within rotor cavity 110. As an example, the density of the hydrophobic fluid can be in a range of 1100 kg/m3 to 1500 kg/m3.
The ingress of well fluids into motor 20 is not only a function of the density of the hydrophobic fluid. Surface tension and the viscosity of the hydrophobic fluid also play an important role as well. Surface tension will prevent the hydrophobic fluid escaping from motor 20 because surface tension decreases the wettability of the hydrophobic fluid to the seals. This may be achieved by tailoring the surface tension of the hydrophobic fluid or by treating the seals with an oleo-phobic coating or treatment so that the hydrophobic fluid does not wet the seals and hence will not leak out. Surface tension may be quantified by the contact angle when a drop of the liquid is placed on a surface. In example embodiments of this disclosure, the hydrophobic fluid can have a contact angle of less than 45 degrees, which may be measured using an optical attension meter.
Having a hydrophobic fluid with a sufficient viscosity will result in a hydrophobic fluid that will only flow out of motor 20 under a higher differential pressure; the hydrophobic fluid cannot be squeezed out of motor 20. In embodiments of this disclosure, the hydrophobic fluid can have a viscosity in a range of 10 centistokes@100 deg C. to 66 centistokes@40 deg C.
Membrane 112 is located within liner 100. Membrane 112 can be secured to liner 100 mechanically. Membrane 112 can be formed of a material that binds a component of the wellbore fluid. In particular, membrane 112 can bind a component of the wellbore fluid that could be detrimental to motor 20 if such component enters rotor cavity 110. In an example embodiment, membrane 112 can bind a crude oil of the wellbore fluid. In an alternate example embodiment, membrane 112 can bind a water of the wellbore fluid. In an alternate embodiment membrane 112 can be installed in seal section 22, or can be located both within liner 100 and seal section 22.
Embodiments of this disclosure can maintain a simple workbench assembly process of motor 20, and is particular useful for long and skinny motors. In order to assemble motor 20 intermediate rotor bearing assembly 76 and rotor member 84 can be positioned around and circumscribe rotor shaft 74 to form rotor assembly 72. Stator body 64 can be positioned within motor housing 44. Head member 50 can be sealingly connected to motor housing 44 and motor tails 56 can be made up with stator wire overhang 108. Backup ring 58 can be sealingly connected to head member 50 and liner 100 can be sealingly connected to backup ring 58 to form a hermetically sealed space 104 that contains stator 62.
Rotor assembly 72 can then be pulled into interior cavity 66 of stator body 64 within motor housing 44. Outer series of edges 106 of intermediate rotor bearing assembly 76 can engage the inner diameter surface of liner 100 as rotor assembly 72 is pulled into motor housing 44. The polygonal shape of outer series of edges 106 and inner diameter surface of liner 100 allows rotor assembly 72 to be pulled into motor housing 44 with little resistance and prevents intermediate rotor bearing assembly 76 from rotating relative to motor housing 44. Bearing housing 92 can be secured to backup ring 58 to maintain rotor assembly 72 within motor housing 44.
Motor 20 can be made up with seal section 22 and pump 18 to form electrical submersible pump assembly 16. Electrical submersible pump assembly 16 can then be lowered into subterranean well 10 with deployment string 38. Electrical submersible pump assembly 16 can then be operated to lift production fluids in a direction out of subterranean well 10. If motor 20 requires repair or maintenance, rotor assembly 72 can be pulled out of motor housing 44 in a reverse series of steps.
Embodiments of this disclosure therefore provide systems and methods for hermetically sealing a stator for providing a greater motor life and reduced needs for servicing the motor. Having a rotor cavity that is separate from the stator prevents wellbore fluids from contacting the stator windings and pothead, and allows for alternative lubricating or cooling oils to be used in the rotor cavity and seal section without the risk of such fluids degrading the stator. Moreover, if for some reason the wellbore fluids do enter the rotor cavity, a membrane can bind components of the wellbore fluid that could result in damage to the motor.
Embodiments of the disclosure described herein, therefore, are well adapted to carry out the objects and attain the ends and advantages mentioned, as well as others inherent therein. While a presently preferred embodiment of the disclosure has been given for purposes of disclosure, numerous changes exist in the details of procedures for accomplishing the desired results. These and other similar modifications will readily suggest themselves to those skilled in the art, and are intended to be encompassed within the spirit of the present disclosure and the scope of the appended claims.
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