Patent Application
20090151391
1. Field of the Invention
This invention relates to methods and apparatuses for liquefying natural gas. In another aspect, the invention concerns a liquefied natural gas (LNG) facility employing a heavies enriching stream.
2. Description of the Prior Art
Cryogenic liquefaction is commonly used to convert natural gas into a more convenient form for transportation and/or storage. Because liquefying natural gas greatly reduces its specific volume, large quantities of natural gas can be economically transported and/or stored in liquefied form.
Transporting natural gas in its liquefied form can effectively link a natural gas source with a distant market when the source and market are not connected by a pipeline. This situation commonly arises when the source of natural gas and the market for the natural gas are separated by large bodies of water. In such cases, liquefied natural gas (LNG) can be transported from the source to the market using specially designed ocean-going LNG tankers.
Storing natural gas in its liquefied form can help balance out periodic fluctuations in natural gas supply and demand. In particular, LNG can be “stockpiled” for use when natural gas demand is low and/or supply is high. As a result, future demand peaks can be met with LNG from storage, which can be vaporized as demand requires.
Several methods exist for liquefying natural gas. Some methods produce a pressurized LNG (PLNG) product that is useful, but requires expensive pressure-containing vessels for storage and transportation. Other methods produce an LNG product having a pressure at or near atmospheric pressure. In general, these non-pressurized LNG production methods involve cooling a natural gas stream via indirect heat exchange with one or more refrigerants and then expanding the cooled natural gas stream to near atmospheric pressure. In addition, most LNG facilities employ one or more systems to remove contaminants (e.g., water, acid gases, nitrogen, and ethane and heavier components) from the natural gas stream at different points during the liquefaction process.
In general, LNG facilities are designed and operated to provide LNG to a single market in a certain region of the world. Because natural gas specifications, such as, for example, higher heating value (HHV), Wobbe index, methane content, ethane content, C3+ content, and inerts content, vary widely throughout the world, LNG facilities are typically optimized to meet a certain set of specifications for a single market. Thus, most existing facilities are equipped only to process natural gas feed streams within a relatively narrow composition range. For example, when an LNG facility designed and operated to effectively process a lean (i.e., heavies-lean) natural gas feed stream is forced to process a rich natural gas stream due to, for example, change in feed gas source or upstream process upset, the plant's LNG production rate and product quality are adversely affected.
One proposed solution to managing natural gas feed streams having widely varying compositions is to constantly adjust the operating conditions of the distillation column(s) in the heavies removal zone based on the compositional changes in the feed gas. The flexibility of this proposed solution is typically limited by equipment constraints. In addition, frequently altering plant process conditions introduces operational instability and can result in large volumes of off-spec product and/or product loss. Another proposed solution is to equip LNG facilities with auxiliary process equipment (e.g. distillation columns, turboexpanders, and/or compressors) to be used when the facility processes feed gas outside its design composition range. The main drawbacks associated with this proposed solution are the increased capital cost and operational complexity associated with adding process equipment to a new or existing plant configuration.
Thus, a need exists for an LNG facility capable of managing natural gas feed streams having widely varying compositions in a way that maximizes the production of on-spec LNG product while minimizing capital and operating costs for the entire facility.
In one embodiment of the present invention, there is provided a process for liquefying a natural gas stream in an LNG facility, the process comprising: (a) combining at least a portion of the natural gas stream with a heavies enriching stream to thereby form a heavies enriched natural gas stream; (b) separating at least a portion of the heavies enriched natural gas stream in a first distillation column to thereby provide a first overhead stream and a first bottoms stream; and (c) separating at least a portion of the first bottoms stream in a second distillation column to thereby provide a second bottoms stream, wherein the heavies enriching stream comprises at least a portion of the second bottoms stream.
In another embodiment of the present invention, there is provided a process for liquefying a natural gas stream in an LNG facility, the process comprising: (a) introducing a heavies enriching stream into the natural gas stream to thereby produce a heavies enriched natural gas stream; (b) separating at least a portion of the heavies enriched natural gas stream in a distillation column to thereby provide an overhead stream and a bottoms stream, wherein the heavies enriching stream comprises at least a portion of the bottoms stream; and (c) adjusting the flow rate of the heavies enriching stream introduced into the natural gas stream to maintain a C3+/C2 molar ratio in the heavies enriched natural gas stream of at least about 0.3:1.
In yet another embodiment of the present invention, there is provided an LNG facility comprising a natural gas feed conduit, a first distillation column, and a second distillation column. The first distillation column defines a first fluid inlet, upper outlet, and lower outlet. The first fluid inlet is coupled in fluid flow communication with the natural gas feed conduit. The second distillation column defines a second fluid inlet, upper outlet, and lower outlet. The second fluid inlet is coupled in fluid flow communication with the first lower outlet. The second lower outlet is coupled in fluid flow communication with the natural gas feed conduit at an enrichment location upstream of the first distillation column.
Certain embodiments of the present invention are described in detail below with reference to the enclosed figures, wherein:
a is a simplified overview of a cascade-type LNG facility configured in accordance with one embodiment of the present invention;
b is a flow chart of the major steps involved in executing one embodiment of the present invention; and
The present invention can be implemented in a facility used to cool natural gas to its liquefaction temperature to thereby produce liquefied natural gas (LNG). The LNG facility generally employs one or more refrigerants to extract heat from the natural gas and then reject the heat to the environment. Numerous configurations of LNG systems exist, and the present invention may be implemented many different types of LNG systems.
In one embodiment, the present invention can be implemented in a mixed refrigerant LNG system. Examples of mixed refrigerant processes can include, but are not limited to, a single refrigeration system using a mixed refrigerant, a propane pre-cooled mixed refrigerant system, and a dual mixed refrigerant system.
In another embodiment, the present invention is implemented in a cascade LNG system employing a cascade-type refrigeration process using one or more pure component refrigerants. The refrigerants utilized in cascade-type refrigeration processes can have successively lower boiling points in order to maximize heat removal from the natural gas stream being liquefied. Additionally, cascade-type refrigeration processes can include some level of heat integration. For example, a cascade-type refrigeration process can cool one or more refrigerants having a higher volatility via indirect heat exchange with one or more refrigerants having a lower volatility. In addition to cooling the natural gas stream via indirect heat exchange with one or more refrigerants, cascade and mixed-refrigerant LNG systems can employ one or more expansion cooling stages to simultaneously cool the LNG while reducing its pressure to near atmospheric pressure.
a illustrates one embodiment of a simplified LNG facility employing a heavies recycle stream. The cascade LNG facility of
In accordance with one embodiment of the present invention, first, second, and third refrigeration cycles 13, 14, 15 can employ respective first, second, and third refrigerants having successively lower boiling points. For example, the first, second, and third refrigerants can have mid-range boiling points at standard pressure (i.e., mid-range standard boiling points) within about 20° F., within about 110° F., or within 5° F. of the standard boiling points of propane, ethylene, and methane, respectively. In one embodiment, the first refrigerant can comprise at least about 75 mole percent, at least about 90 mole percent, at least 95 mole percent, or can consist essentially of propane, propylene, or mixtures thereof. The second refrigerant can comprise at least about 75 mole percent, at least about 90 mole percent, at least 95 mole percent, or can consist essentially of ethane, ethylene, or mixtures thereof. The third refrigerant can comprise at least about 75 mole percent, at least about 90 mole percent, at least 95 mole percent, or can consist essentially of methane.
As shown in
First refrigerant chiller 18 can comprise one or more cooling stages operable to reduce the temperature of the incoming natural gas stream in conduit 100 by about 40 to about 210° F., about 50 to about 190° F., or 75 to 150° F. Typically, the natural gas entering first refrigerant chiller 24 via conduit 100 can have a temperature in the range of from about 0 to about 200° F., about 20 to about 180° F., or 50 to 165° F., while the temperature of the cooled natural gas stream exiting first refrigerant chiller 18 can be in the range of from about −65 to about 0° F., about −50 to about −10° F., or −35 to −15° F. In general, the pressure of the natural gas stream in conduit 100 can be in the range of from about 100 to about 3,000 pounds per square inch absolute (psia), about 250 to about 1,000 psia, or 400 to 800 psia. Because the pressure drop across first refrigerant chiller 18 can be less than about 100 psi, less than about 50 psi, or less than 25 psi, the cooled natural gas stream in conduit 101 can have substantially the same pressure as the natural gas stream in conduit 100.
The cooled natural gas stream (also referred to herein as the “cooled predominantly methane stream”) exiting first refrigeration cycle 13 can then enter second refrigeration cycle 14, which can comprise a second refrigerant compressor 19, a second cooler 20, and a second refrigerant chiller 21. Compressed refrigerant can be discharged from second refrigerant compressor 19 and can subsequently be cooled and at least partially liquefied in cooler 20 prior to entering second refrigerant chiller 21. Second refrigerant chiller 21 can employ a plurality of cooling stages to progressively reduce the temperature of the predominantly methane stream in conduit 101 by about 50 to about 180° F., about 65 to about 150° F., or 95 to 125° F. via indirect heat exchange with the vaporizing second refrigerant. As shown in
In one embodiment, the natural gas feed stream in conduit 100 can comprise at least about 5 mole percent, at least about 10 mole percent, or at least 15 mole percent C2+. The presence of these ethane and heavier components generally results in the formation of a C2+-rich liquid phase in one or more of the cooling stages of second refrigeration cycle 14. In order to remove the desired heavies, at least a portion of the cooled predominantly methane feed stream passing through second refrigerant chiller 21 can be withdrawn via conduit 102 and processed in heavies removal zone 11. The feed stream entering heavies removal zone 11 in conduit 102 can have a temperature in the range of from about −160 to about −50° F., about −140 to about −65° F., or −115 to −85° F. and a pressure that is within about 5 percent, about 10 percent, or 15 percent of the pressure of the natural gas feed stream in conduit 100.
Heavies removal zone 11 can comprise one or more gas-liquid separators operable to remove at least a portion of the heavy hydrocarbon material from the predominantly methane natural gas stream. In one embodiment, as depicted in
As illustrated in
According to one embodiment, the natural gas feed stream in conduit 100 can fluctuate between comprising a lean natural gas feed stream and a rich natural gas feed stream. In general, a lean natural gas feed stream can comprise less than about 1 mole percent, less than about 0.5 mole percent, or less than 0.25 mole percent C3+ components. A rich natural gas stream typically comprises greater than about 1.1 mole percent, greater than about 2 mole percent, or greater than 5 mole percent C3+ components. In order to produce an on-spec LNG and/or NGL product despite fluctuations in the natural gas feed composition to the plant, the LNG facility depicted in
The heavies enriching stream can be withdrawn from one or more of several locations within the LNG facility or can originate from an external source, such as, for example, a gas plant or other location. In one embodiment of the present invention depicted in
Employing a heavies enriching stream can increase overall production of on-spec LNG by helping stabilize plant operations and by increasing the separation efficiency of difficult-to-remove components (e.g., ethane) from the predominantly methane stream processed in heavies removal zone 11. For example, in one embodiment, the molar ratio of the ethane content of the overhead product stream exiting heavies removal column 25 to the ethane content of the bottoms product stream exiting heavies removal column 25 can be less than about 0.25:1, less than about 0.10:1, or less than 0.05:1. Typically, when a heavies enriching stream is employed, an overhead product exiting heavies removal column 25 via conduit 103 can have an ethane content of less than about 10 mole percent, less than about 8 mole percent, less than about 6 mole percent, or less than 5 mole percent. As a result, the LNG produced in the LNG facility can comprise less than about 10 mole percent, less than about 8 mole percent, or less than 6 mole percent C2+ components. This allows the LNG produced to meet strict market requirements, such as, for example, the North American West Coast specification (NAWC spec), which requires LNG having an ethane content less than 6 mole percent at the product terminal.
Referring now to
As shown by block 502 in
According to decision block 504, the next step comprises comparing the determined and target property values of the selected stream. If the difference between the target and the determined values are within the comparison threshold established in the previous step, the flow rate of the heavies enriching stream can be maintained at its current rate, as indicated by block 506a. Alternatively, if the difference between the determined value and the target value of the selected compositional property exceeds the threshold limit established in the previous step, the flow rate of the heavies enriching stream can be adjusted accordingly, as shown by block 506b.
Typically, a flow control system can be employed to perform the steps depicted in blocks 504 and 506a,b. One embodiment illustrated in
Referring back to heavies removal zone 11 illustrated in
As illustrated in
As shown in
Each expansion stage may additionally employ one or more vapor-liquid separators operable to separate the vapor phase (i.e., the flash gas stream) from the cooled liquid stream. As previously discussed, third refrigeration cycle 15 can comprise an open-loop refrigeration cycle, closed-loop refrigeration cycle, or any combination thereof. When third refrigeration cycle 15 comprises a closed-loop refrigeration cycle, the flash gas stream can be used as fuel within the facility or routed downstream for storage, further processing, and/or disposal. When third refrigeration cycle 15 comprises an open-loop refrigeration cycle, at least a portion of the flash gas stream exiting expansion section 12 be used as a refrigerant to cool at least a portion of the natural gas stream in conduit 104. Generally, when third refrigerant cycle 15 comprises an open-loop cycle, the third refrigerant can comprise at least 50 weight percent, at least about 75 weight percent, or at least 90 weight percent of flash gas from expansion section 12, based on the total weight of the stream. As illustrated in
As shown in
Referring now to
The operation of the LNG facility illustrated in
The cooled natural gas stream from high-stage propane chiller 33 (also referred to herein as the “methane-rich stream”) flows via conduit 114 to a separation vessel 40, wherein the gaseous and liquid phases are separated. The liquid phase, which can be rich in propane and heavier components (C3+), is removed via conduit 303. The predominately vapor phase exits separator 40 via conduit 116 and can then enter intermediate-stage propane chiller 34, wherein the stream is cooled in indirect heat exchange means 41 via indirect heat exchange with a yet-to-be-discussed propane refrigerant stream. The resulting two-phase methane-rich stream in conduit 118 can then be routed to low-stage propane chiller 35, wherein the stream can be further cooled via indirect heat exchange means 42. The resultant predominantly methane stream can then exit low-stage propane chiller 35 via conduit 120. Subsequently, the cooled methane-rich stream in conduit 120 can be routed to high-stage ethylene chiller 53, which will be discussed in more detail shortly.
The vaporized propane refrigerant exiting high-stage propane chiller 33 is returned to the high-stage inlet port of propane compressor 31 via conduit 306. The residual liquid propane refrigerant in high-stage propane chiller 33 can be passed via conduit 308 through a pressure reduction means, illustrated here as expansion valve 43, whereupon a portion of the liquefied refrigerant is flashed or vaporized. The resulting cooled, two-phase refrigerant stream can then enter intermediate-stage propane chiller 34 via conduit 310, thereby providing coolant for the natural gas stream and yet-to-be-discussed ethylene refrigerant stream entering intermediate-stage propane chiller 34. The vaporized propane refrigerant exits intermediate-stage propane chiller 34 via conduit 312 and can then enter the intermediate-stage inlet port of propane compressor 31. The remaining liquefied propane refrigerant exits intermediate-stage propane chiller 34 via conduit 314 and is passed through a pressure-reduction means, illustrated here as expansion valve 44, whereupon the pressure of the stream is reduced to thereby flash or vaporize a portion thereof. The resulting vapor-liquid refrigerant stream then enters low-stage propane chiller 35 via conduit 316 and cools the methane-rich and yet-to-be-discussed ethylene refrigerant streams entering low-stage propane chiller 35 via conduits 118 and 206, respectively. The vaporized propane refrigerant stream then exits low-stage propane chiller 35 and is routed to the low-stage inlet port of propane compressor 31 via conduit 318 wherein it is compressed and recycled as previously described.
As shown in
Turning now to ethylene refrigeration cycle 50 in
The remaining liquefied refrigerant in conduit 220 can re-enter ethylene economizer 56, wherein the stream can be further sub-cooled by an indirect heat exchange means 61. The resulting cooled refrigerant stream exits ethylene economizer 56 via conduit 222 and can subsequently be routed to a pressure reduction means, illustrated here as expansion valve 62, whereupon the pressure of the stream is reduced to thereby vaporize or flash a portion thereof. The resulting, cooled two-phase stream in conduit 224 enters intermediate-stage ethylene chiller 54, wherein the refrigerant stream can cool the natural gas stream in conduit 122 entering intermediate-stage ethylene chiller 54 via an indirect heat exchange means 63. As shown in
The vaporized ethylene refrigerant exits intermediate-stage ethylene chiller 54 via conduit 226, whereafter the stream can combine with a yet-to-be-discussed ethylene vapor stream in conduit 238. The combined stream in conduit 239 can enter ethylene economizer 56, wherein the stream is warmed in an indirect heat exchange means 64 prior to being fed into the low-stage inlet port of ethylene compressor 51 via conduit 230. As shown in
The remaining liquefied ethylene refrigerant exits intermediate-stage ethylene chiller 54 via conduit 228 prior to entering low-stage ethylene chiller/condenser 55, wherein the refrigerant can cool the methane-rich stream entering low-stage ethylene chiller/condenser via conduit 128 in an indirect heat exchange means 65. In one embodiment shown in
The cooled natural gas stream exiting low-stage ethylene chiller/condenser can also be referred to as the “pressurized LNG-bearing stream.” As shown in
The liquid phase exiting high-stage methane flash drum 82 via conduit 142 can enter secondary methane economizer 74, wherein the methane stream can be cooled via indirect heat exchange means 92. The resulting cooled stream in conduit 144 can then be routed to a second expansion stage, illustrated here as intermediate-stage expansion device 83. Intermediate-stage expansion device 83 reduces the pressure of the methane stream passing therethrough to thereby reduce the stream's temperature by vaporizing or flashing a portion thereof. The resulting two-phase methane-rich stream in conduit 146 can then enter intermediate-stage methane flash drum 84, wherein the liquid and vapor portions of the stream can be separated and can exit the intermediate-stage flash drum via respective conduits 148 and 150. The vapor portion (i.e., the intermediate-stage flash gas) in conduit 150 can re-enter secondary methane economizer 74, wherein the stream can be heated via an indirect heat exchange means 87. The warmed stream can then be routed via conduit 152 to main methane economizer 73, wherein the stream can be further warmed via an indirect heat exchange means 77 prior to entering the intermediate-stage inlet port of methane compressor 71 via conduit 154.
The liquid stream exiting intermediate-stage methane flash drum 84 via conduit 148 can then pass through a low-stage expansion device 85, whereupon the pressure of the liquefied methane-rich stream can be further reduced to thereby vaporize or flash a portion thereof. The resulting cooled, two-phase stream in conduit 156 can then enter low-stage methane flash drum 86, wherein the vapor and liquid phases can be separated. The liquid stream exiting low-stage methane flash drum 86 can comprise the liquefied natural gas (LNG) product. The LNG product, which is at about atmospheric pressure, can be routed via conduit 158 downstream for subsequent storage, transportation, and/or use.
The vapor stream exiting low-stage methane flash drum (i.e., the low-stage methane flash gas) in conduit 160 can be routed to secondary methane economizer 74, wherein the stream can be warmed via an indirect heat exchange means 89. The resulting stream can exit secondary methane economizer 74 via conduit 162, whereafter the stream can be routed to main methane economizer 73 to be further heated via indirect heat exchange means 78. The warmed methane vapor stream can then exit main methane economizer 73 via conduit 164 prior to being routed to the low-stage inlet port of methane compressor 71. Methane compressor 71 can comprise one or more compression stages. In one embodiment, methane compressor 71 comprises three compression stages in a single module. In another embodiment, the compression modules can be separate, but can be mechanically coupled to a common driver. Generally, when methane compressor 71 comprises two or more compression stages, one or more intercoolers (not shown) can be provided between subsequent compression stages. As shown in
Upon being cooled in propane refrigeration cycle 30, the methane refrigerant stream can be discharged into conduit 130 and subsequently routed to main methane economizer 73, wherein the stream can be further cooled via indirect heat exchange means 79. The resulting sub-cooled stream exits main methane economizer 73 via conduit 168 and can then combined with the heavies-depleted stream exiting heavies removal zone 95 via conduit 126, as previously discussed.
Turning now to heavies removal zone 95, the cooled, at least partially condensed effluent exiting intermediate-stage ethylene chiller 54 via conduit 124 can be routed into the inlet of first distillation column 96, as shown in
As illustrated in
In one embodiment of the present invention, the LNG production systems illustrated in
The LNG facility depicted in
As illustrated by the results presented in Table 1, increasing the volumetric flow rate of the heavies enriching stream introduced into the natural gas feed stream (to thereby increase the C3+/C2 molar ratio in the enriched heavies removal stream) reduces the ethane content of the overhead stream withdrawn from first distillation column 96. Because the overhead stream exiting first distillation column 96 ultimately becomes the final LNG product, utilizing a heavies enriching stream can help control the ethane content of the final LNG product.
The present description uses numerical ranges to quantify certain parameters relating to the invention. It should be understood that when numerical ranges are provided, such ranges are to be construed as providing literal support for claim limitations that only recite the lower value of the range as well as claims limitation that only recite the upper value of the range. For example, a disclosed numerical range of 10 to 100 provides literal support for a claim reciting “greater than 10” (with no upper bounds) and a claim reciting “less than 100” (with no lower bounds).
As used herein, the terms “a,” “an,” “the,” and “said” means one or more.
As used herein, the term “and/or,” when used in a list of two or more items, means that any one of the listed items can be employed by itself, or any combination of two or more of the listed items can be employed. For example, if a composition is described as containing components A, B, and/or C, the composition can contain A alone; B alone; C alone; A and B in combination; A and C in combination; B and C in combination; or A, B, and C in combination.
As used herein, the term “cascade-type refrigeration process” refers to a refrigeration process that employs a plurality of refrigeration cycles, each employing a different refrigerant to successively cool natural gas.
As used herein, the term “closed-loop refrigeration cycle” refers to a refrigeration cycle wherein substantially no refrigerant enters or exits the cycle during normal operation.
As used herein, the term “compositional property” refers to a property associated with the composition of a stream.
As used herein, the terms “comprising,” “comprises,” and “comprise” are open-ended transition terms used to transition from a subject recited before the term to one or elements recited after the term, where the element or elements listed after the transition term are not necessarily the only elements that make up of the subject.
As used herein, the terms “containing,” “contains,” and “contain” have the same open-ended meaning as “comprising,” “comprises,” and “comprise,” provided above.
As used herein, the terms “economizer” or “economizing heat exchanger” refer to a configuration utilizing a plurality of heat exchangers employing indirect heat exchange means to efficiently transfer heat between process streams.
As used herein, the terms “having,” “has,” and “have” have the same open-ended meaning as “comprising,” “comprises,” and “comprise,” provided above.
As used herein, the term “heavies enriching stream” refers to any stream operable to enrich (i.e., increase the heavies content of) the stream with which it is combined.
As used herein, the terms “heavy hydrocarbon” and “heavies” refer to any component that is less volatile (i.e., has a higher boiling point) than methane.
As used herein, the terms “including,” “includes,” and “include” have the same open-ended meaning as “comprising,” “comprises,” and “comprise,” provided above.
As used herein, the term “lean natural gas” refers to natural gas comprising less than about 1 mole percent C3+ material.
As used herein, the term “mid-range standard boiling point” refers to the temperature at which half of the weight of a mixture of physical components has been vaporized (i.e., boiled off) at standard pressure.
As used herein, the term “mixed refrigerant” refers to a refrigerant containing a plurality of different components, where no single component makes up more than 75 mole percent of the refrigerant.
As used herein, the term “natural gas” means a stream containing at least 75 mole percent methane, with the balance being ethane, higher hydrocarbons, nitrogen, carbon dioxide, and/or a minor amount of other contaminants such as mercury, hydrogen sulfide, and mercaptan.
As used herein, the terms “natural gas liquids” or “NGL” refer to mixtures of hydrocarbons whose components are, for example, typically heavier than ethane. Some examples of hydrocarbon components of NGL streams include propane, butane, and pentane isomers, benzene, toluene, and other aromatic compounds.
As used herein, the term “open-loop refrigeration cycle” refers to a refrigeration cycle wherein at least a portion of the refrigerant employed during normal operation originates from the fluid being cooled by the refrigeration cycle.
As used herein, the terms “predominantly,” “primarily,” “principally,” and “in major portion,” when used to describe the presence of a particular component of a fluid stream, means that the fluid stream comprises at least 50 mole percent of the stated component. For example, a “predominantly” methane stream, a “primarily” methane stream, a stream “principally” comprised of methane, or a stream comprised “in major portion” of methane each denote a stream comprising at least 50 mole percent methane.
As used herein, the term “pure component refrigerant” means a refrigerant that is not a mixed refrigerant.
As used herein, the term “rich natural gas” refers to natural gas having greater than about 1.1 mole percent C3+ material.
As used herein, the terms “upstream” and “downstream” refer to the relative positions of various components of a natural gas liquefaction facility along the main flow path of natural gas through the facility.
The preferred forms of the invention described above are to be used as illustration only, and should not be used in a limiting sense to interpret the scope of the present invention. Modifications to the exemplary embodiments, set forth above, could be readily made by those skilled in the art without departing from the spirit of the present invention.
The inventors hereby state their intent to rely on the Doctrine of Equivalents to determine and assess the reasonably fair scope of the present invention as pertains to any apparatus not materially departing from but outside the literal scope of the invention as set forth in the following claims.
