U.S. patent application number 11/231419 was filed with the patent office on 2007-03-22 for method and system for enhancing hydrocarbon production from a hydrocarbon well.
Invention is credited to David Randolph Smith.
Application Number | 20070062704 11/231419 |
Document ID | / |
Family ID | 37882921 |
Filed Date | 2007-03-22 |
United States Patent
Application |
20070062704 |
Kind Code |
A1 |
Smith; David Randolph |
March 22, 2007 |
Method and system for enhancing hydrocarbon production from a
hydrocarbon well
Abstract
Production from a hydrocarbon well is facilitated when heat
generated by surface equipment used to produce hydrocarbons from
the well is continuously injected into the well to heat the well
system. The heat may be further concentrated using a vortex tube to
separate a hot component from a cold component of compressed gas
injected into the well.
Inventors: |
Smith; David Randolph;
(US) |
Correspondence
Address: |
THOMAS, KAYDEN, HORSTEMEYER & RISLEY, LLP
100 GALLERIA PARKWAY, NW
STE 1750
ATLANTA
GA
30339-5948
US
|
Family ID: |
37882921 |
Appl. No.: |
11/231419 |
Filed: |
September 21, 2005 |
Current U.S.
Class: |
166/303 ;
166/57 |
Current CPC
Class: |
E21B 43/24 20130101;
E21B 36/006 20130101 |
Class at
Publication: |
166/303 ;
166/057 |
International
Class: |
E21B 36/00 20060101
E21B036/00 |
Claims
1. A method of enhancing production of hydrocarbons from a
hydrocarbon well comprising continuously injecting into the
hydrocarbon well heat generated by surface equipment used to
produce the hydrocarbons from the well or heat generated by surface
equipment used to compress the hydrocarbons for injection into a
pipeline.
2. The method as claimed in claim 1 wherein the hydrocarbon well is
a natural gas well and the method further comprises: compressing
the natural gas produced from the well at the wellhead using a
compressor; and continuously diverting a proportion of the
compressed natural gas back into the well to heat the well.
3. The method as claimed in claim 1 wherein diverting a proportion
of the compressed natural gas back into the well comprises
diverting the compressed natural gas into a production tubing of
the well.
4. The method as claimed in claim 1 wherein diverting a proportion
of the compressed natural gas back into the well comprises
diverting the compressed natural gas into an annulus between
production tubing and a casing of the well.
5. The method as claimed in claim 2 further comprising using a
vortex tube to separate the compressed natural gas into a hot
natural gas component and a cold natural gas component and
continuously diverting only the hot natural gas component back into
the well.
6. The method as claimed in claim 5 further comprising delivering
the cold natural gas component to at least one of a natural gas
distribution system and a fuel intake of a prime mover used to
produce hydrocarbons from the well or to compress natural gas
produced by the well.
7. The method as claimed in claim 6 wherein delivering the cold
natural gas component to the natural gas distribution system
comprises injecting the cold natural gas component directly into
the gas distribution system.
8. The method as claimed in claim 1 wherein the hydrocarbon well is
an oil well, and the method further comprises: continuously
collecting heat generated by a prime mover used to pump crude oil
from the oil well and transferring the heat to a heat transfer
medium; and continuously recirculating the heat transfer medium
through the well to inject the heat into the well.
9. The method as claimed in claim 8 wherein the heat transfer
medium comprises a compressed gas.
10. The method as claimed in claim 9 wherein the pump comprises a
jack pump and the method further comprises: continuously
circulating the compressed gas down a hollow sucker rod string
connected to the jack pump; continuously drawing the compressed gas
returned to a wellhead of the well; and continuously passing the
returned compressed gas through a heat exchanger for transferring
to the compressed gas the heat generated by the prime mover.
11. A method of enhancing production from a natural gas well,
comprising: flowing natural gas from the well to a compressor and
compressing the natural gas; diverting a proportion of the
compressed natural gas back into the well; and delivering a
remainder of the compressed natural gas to a natural gas
distribution system.
12. The method as claimed in claim 11 wherein compressing the
natural gas comprises compressing the natural gas using a
compressor driven by an internal combustion engine, and at least a
proportion of heat output by the internal combustion engine is used
to further heat the compressed natural gas before it is diverted
back into the well.
13. The method as claimed in claim 12 further comprising recovering
exhaust heat from the internal combustion engine using a heat
exchanger and further heating the compressed natural gas using the
recovered exhaust heat.
14. The method as claimed in claim 12 further comprising recovering
heat from an engine block of the internal combustion engine using a
heat exchanger and further heating the compressed natural gas using
the recovered engine block heat.
15. The method as claimed in claim 11 further comprising using at
least one vortex tube to separate a hot natural gas component of
the compressed natural gas from a cold natural gas component of the
compressed natural gas, and injecting the hot natural gas component
back into the well.
16. The method as claimed in claim 15 further comprising delivering
the cold natural gas component to the natural gas distribution
system.
17. The method as claimed in claim 11 further comprising mixing
additives with the compressed natural gas as the compressed natural
gas is diverted back into the well.
18. The method as claimed in claim 17 wherein the additives
comprise at least one of: fresh water, a corrosion inhibitor; a
scale inhibitor; a paraffin inhibitor; an asphaltene inhibitor; a
salt inhibitor; a surfactant; and, a freeze point depressant.
19. The method as claimed in claim 11 wherein diverting the
compressed natural gas comprises diverting the compressed natural
gas down a production tubing string suspended inside a casing of
the well and producing natural gas from an annulus between the
production tubing string and the casing of the well.
20. The method as claimed in claim 11 wherein diverting the
compressed natural gas comprises diverting the compressed natural
gas down a casing of the well and producing the natural gas from a
production tubing string suspended inside the casing.
21. A system for enhancing hydrocarbon production from a
hydrocarbon well, comprising: a power source for continuously
injecting into the well a compressed gas heated by heat generated
by surface equipment used to produce the hydrocarbon from the well
or to compress the hydrocarbons produced by the well.
22. The system as claimed in claim 21 wherein the hydrocarbon well
is a natural gas well, and the power source comprises a compressor
for compressing natural gas produced from the well, the system
further comprising: a diverter line for diverting back into the
well a proportion of a hot compressed natural gas stream compressed
by the compressor; and a control valve for controlling the
proportion of the hot compressed natural gas stream diverted back
into the well.
23. The system as claimed in claim 22 wherein the control valve
comprises a choke.
24. The system as claimed in claim 22 further comprising an
additive system for mixing additives with the hot compressed
natural gas diverted back into the well.
25. The system as claimed in claim 22 wherein the additive system
comprises an additive reservoir and an additive pump for pumping an
additive from the additive reservoir into the diverter line.
26. The system as claimed in claim 21 further comprising a heat
exchanger for extracting heat generated by a prime mover used to
drive the compressor.
27. The system as claimed in claim 26 wherein the prime mover is an
internal combustion engine and the heat exchanger recuperates heat
from exhaust gases of the internal combustion engine.
28. The system as claimed in claim 26 wherein the prime mover is an
internal combustion engine and the heat exchanger recuperates heat
from an engine block of the internal combustion engine.
29. The system as claimed in claim 21 further comprising: a vortex
tube connected to the diverter line, the vortex tube separating the
compressed gas into a hot gas component and a cold gas component;
and a hot gas injector line for injecting the hot gas component
into the well.
30. The system as claimed in claim 29 further comprising a cold gas
injector line for delivering the cold gas component to a natural
gas distribution system.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This is the first application filed for the present
invention.
MICROFICHE APPENDIX
[0002] Not applicable.
TECHNICAL FIELD
[0003] The invention relates generally to producing hydrocarbons
from a hydrocarbon well and, in particular, to enhancing
hydrocarbon production from a hydrocarbon well by heating the
hydrocarbon well using heat generated by surface equipment used to
produce the hydrocarbons from the well.
BACKGROUND OF THE INVENTION
[0004] Hydrocarbons production zones, especially subterranean
natural gas production zones have a natural pressure when the
hydrocarbon well is drilled to communicate with the zone. The
production zone also has a natural geothermal temperature.
Production zones often contain natural gas and other fluids such as
hydrocarbon condensates, water, crude oil, etc. All of those fluids
in the production zone are at ambient temperature and pressure when
the well bore is drilled. Normally, in a commercial gas well the
original pressure and temperature is sufficient to permit the
natural gas to expand and move to a lower pressure at the surface
of the well. Frequently, the original flow rate has a velocity
sufficient to carry all of the fluids out of the production zone to
the surface. Consequently, in many natural gas wells other fluids
such as water and hydrocarbon condensates are produced along with
the natural gas. However, as the well matures the pressure in the
production zone is depleted and a velocity of hydrocarbons produced
at the wellbore decreases, allowing some of the fluids to fall
below a critical velocity for the natural gas to lift the fluids
from the well. Furthermore, the expanding natural gas cools as it
rises to the surface, permitting liquids to condense in the
wellbore at the reduced pressures and temperatures in the upper
regions of the well. In off-shore wells, and particularly in deep
water wells, the well fluids have to pass through long sub-sea
floor lines and risers to the ocean surface. Sea floor temperatures
can be low, causing further cooling of natural gas and potential
plugging of the flow from the well.
[0005] Fluids condensing from the rising natural gas can accumulate
in the wellbore and exert hydrostatic pressure against the
reservoir, restricting the rate at which natural gas can flow from
the well to the surface. Furthermore, the expansion and cooling of
the rising natural gas can cause fluids to freeze causing ice plugs
and resulting in a complete blockage of fluid production. Those ice
plugs are referred to as "clathrates" or "gas hydrates". Gas
hydrates are crystalline solids that look like ice. Gas hydrates
occur when water molecules form a cage-like structure around
smaller "guest molecules". The guest molecules are most commonly
methane, ethane, propane, butane, nitrogen, carbon dioxide and
hydrogen sulfide, of which methane occurs most frequently. The
formation of gas hydrates is exacerbated by cold weather
conditions.
[0006] In many instances, fluid accumulation in a well and the
resulting hydrostatic pressure can cause fluid production to drop
significantly, or to stop completely. In such instances, well
fluids are generally artificially lifted to the surface to enhance
production from the well. Fluids may be lifted using pumps deployed
in the well, pumping natural gas down the well to lift the fluids,
using plunger lift systems. Chemical additives may also be pumped
down the well to inhibit hydrate plugging and fluid accumulation.
Such chemicals are pumped down the well while it is producing.
[0007] It is also been demonstrated that by running electrical
heating cables into the well the temperature of the well system can
be increased to keep the liquids from condensing. While electrical
heating systems are technically achievable, the application of
electrical heat requires the installation of an electrical power
system to the well, the deployment of electrical cable within the
well and a risk of explosion due to electrical sparks in a gaseous
environment.
[0008] It is also common industry practice to reduce the surface
pressure into which the natural gas flows using compressors.
Compressors are used because well fluids may have adequate pressure
to flow to the surface against atmospheric pressure but natural gas
wells produce into natural gas distributions systems, such as
pipelines, through which natural gas is transported to market.
Delivering natural gas to a pipeline requires the natural gas be
pressurized to a pressure slightly higher than the pressure in the
pipeline to permit the natural gas to flow into the pipeline
system. Consequently, there are many compressors in the around
natural gas fields for the purpose of pressurizing the natural gas
to a pressure higher than the pressure in the pipeline. Those
compressors are often located at a central facility where natural
gas from several wells are brought to the facility and compressed
before transfer to the natural gas pipeline.
[0009] As shown in FIG. 1, further pressure reduction in the well
is achieved by placing a compressor 26 at a well site and pulling a
vacuum pressure on the well using the compressor 26 to lower the
surface pressure and to compress the produced natural gas to a
pressure higher than pipeline pressure, to permit the natural gas
to be injected into the pipeline. The compression of the natural
gas increases the temperature of the natural gas and it is
generally required to cool the natural gas prior to injecting it
into a pipeline 34. Otherwise, the temperature in the pipeline
could increase and the amount of natural gas conducted through the
pipeline would be correspondingly reduced. The heat removed from
the hot compressed natural gas is normally exhausted to atmosphere
using any one of a variety of heat exchangers.
[0010] As shown in FIG. 1, natural gas 16 produced from a
production zone 12 enters a casing 10 through perforations 17, in a
manner well understood in the art. For the sake of simplicity of
illustration, the well shown in FIG. 1 is not equipped with
production tubing. The natural gas 16 rises through the casing 10
to wellhead 14 and enters a conduit 18 which conducts the natural
gas to a separator 20. Fluids are separated from the natural gas by
the separator 20 in a manner well known in the art. The fluids flow
through conduit 22 to a fluid tank 24. The remaining natural gas is
delivered to the compressor with the prime mover 26. In most
instances, the prime mover is an internal combustion engine
supplied with fuel through a fuel line 28 connected to the conduit
18. The hot compressed natural gas is output by the compressor
through a conduit 30. As explained above, the compressed natural
gas is generally too hot to be introduced directly into the
pipeline 34. Consequently, a cooler 32 cools the hot compressed
natural gas before it is delivered to pipeline 34. A check valve 36
ensures that natural gas does not escape from the pipeline in the
event that production of natural gas from the well is halted. As
also explained above in detail, gas hydrates 17 frequently form
within the casing 10 in the upper regions of the well. The hydrates
17 can restrict or completely stop production from the well.
[0011] The control and dissolution of gas hydrate plugs is known
and many systems for delivering chemical dissolvers or inhibitors
have been invented. However, such systems generally require
expensive additives and frequent maintenance.
[0012] There therefore exits a need for a simple and inexpensive
system for facilitating production from a hydrocarbon well that
does not require frequent or extensive maintenance.
SUMMARY OF THE INVENTION
[0013] It is therefore an object of the invention to provide a
system for facilitating production from a hydrocarbon well that is
simple to construct, requires little maintenance and uses waste
energy to heat the well system.
[0014] In accordance with one aspect of the invention there is
provided a method of enhancing production from a hydrocarbon well
comprising continuously injecting into the well heat generated by
surface equipment used to produce the hydrocarbon from the
well.
[0015] In accordance with another aspect of the invention there is
provided a method of enhancing production from a natural gas well,
comprising: flowing natural gas from the well to a compressor and
compressing the natural gas; diverting a proportion of the
compressed natural gas back into the well; and delivering a
remainder of the compressed natural gas to a natural gas
distribution system.
[0016] In accordance with yet another aspect of the invention there
is provided a system for enhancing hydrocarbon production from a
hydrocarbon well, comprising: a power source for continuously
injecting into the well a fluid heated by heat generated by surface
equipment used to produce the hydrocarbon from the well.
BRIEF DESCRIPTION OF THE DRAWINGS
[0017] Further features and advantages of the present invention
will become apparent from the following detailed description, taken
in combination with the appended drawings, in which:
[0018] FIG. 1 is a schematic diagram of a prior art system for
producing natural gas from a hydrocarbon well;
[0019] FIG. 2 is an embodiment of a system in accordance with the
invention for producing natural gas from a hydrocarbon well;
[0020] FIG. 3 is a schematic diagram of another embodiment of the
invention for producing the natural gas from the hydrocarbon well;
and
[0021] FIG. 4 is a schematic diagram of yet another embodiment of
the invention for producing crude oil from a hydrocarbon well.
[0022] It will be noted that throughout the appended drawings, like
features are identified by like reference numerals.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT
[0023] The present invention provides a method and system for
enhancing production from a hydrocarbon well. In accordance with
the invention, heat generated by surface equipment used to produce
hydrocarbon from the well or to compress natural gas produced by
the well is continuously injected into well to heat the well.
Heating the well has several benefits, including: a reduction or
elimination of the formation of gas hydrates, condensates and other
solids or fluids that inhibit production from the well; and, in the
case of oil production, paraffins, bitumens and asphaltenes tend to
stay in solution until the oil is produced from the well. Heat
generated by the surface equipment may be delivered directly from
natural gas compressed by a surface compressor; heat recuperated
from a prime mover used to produce natural gas or oil, such as a
compressor motor, compressor engine or a motor or engine use to
drive a surface pump. The heat may be injected into the well by
diverting compressed natural gas back into the well or circulating
a heated, compressed gas into an oil well. Heat recovery can be
enhanced using a vortex tube to increase an efficiency of the
system in accordance with the invention.
[0024] FIG. 2 is a schematic diagram of an embodiment of a system
in accordance with the invention. In this embodiment, natural gas
16 produced from production zone 12 enters the casing 10 through
perforations 17 and migrates upwardly through a production tubing
15. The natural gas is isolated from rising in an annulus between
the casing 10 and the production tubing 15 by a packer 19 provided
with passages 21 closed by check valves 23 which permits heated
compressed natural gas 48 to pass from the annulus into the
production zone as will be explained below in detail. The natural
gas 16 is produced from the well at a natural pressure that is
below the pressure of natural gas in a natural gas distribution
system, such as the pipeline 34 used to distribute the natural gas
to markets. As explained above with reference to FIG. 1, in order
to elevate the pressure of the natural gas to above that of the
pipeline 34 so that it can be injected into the pipeline 34, a
compressor with prime mover 26 is used to compress the natural
gas.
[0025] Compressing natural gas 16 raises a temperature of the
natural gas 16, as well understood in the art. A proportion of the
hot, compressed natural gas is diverted through a diverter line 38
to an annulus between the casing 10 and the production tubing 15.
The compressor and the prime mover 26 therefore provide a power
source for continuously injecting heated natural gas into the well.
The amount of heated natural gas diverted to the annulus is
controlled by a controller 40, a choke for example, so that a
predetermined volume of hot, compressed natural gas 45 is injected
into the annulus. Due to a pressure differential, the hot
compressed natural gas 48 is forced through the passages 21 in the
packer 19 and the check valves 23. The hot compressed natural gas
commingles with the natural gas 16 produced from the production
zone 12 and rises with the uncompressed natural gas 16 through the
production tubing 15 to separator 20, which removes liquids from
the natural gas to the fluid tank 24, as explained above. The
natural gas is then conducted via the compressor intake conduit 30
to the compressor/prime mover 26. After compression, a proportion
of the hot natural gas is diverted back into the well and the heat
of compression is used to continuously heat the well.
[0026] As is understood by those skilled in the art, it may also be
advantageous to add certain additives to the hot compressed natural
gas in order to further facilitate production from the well. If so,
additives stored in an additive tank 42 are pumped by a pump 44
into the diverter line 38 where they mix with the hot compressed
natural gas and are carried down through the annulus and into the
production zone 16 by the hot compressed natural gas 48. The
additives may include any one or more of: fresh water for
dissolving salt deposits; a corrosion inhibitor for protecting
downhole metal components of the well system; a scale inhibitor to
inhibit the deposit of scale on downhole equipment; a paraffin
inhibitor to control paraffin deposition on downhole equipment; an
asphaltene inhibitor to control asphaltene deposition; a salt
deposit inhibitor to control salt deposit on downhole equipment; a
surfactant to reduce surface tension and improve natural gas
production; and, a freeze point depressant to further inhibit gas
hydrate formation.
[0027] FIG. 3 is a schematic diagram of another embodiment of the
invention for producing natural gas 16 from a production zone 12.
In accordance with this embodiment, heat recovery is improved using
at least one of a heat exchanger 60 and a vortex tube 70, as will
be explained below in more detail. This embodiment is particularly
useful in cold environments such as production facilities located
in higher latitudes and/or deep sea wells. As will be further
noted, the injection of the hot compressed natural gas in this
embodiment is through the production tubing 15 whereas natural gas
is produced from the well via the annulus between the casing 10 and
the production tubing 15. It should be understood by those skilled
in the art that the arrangement shown in FIG. 2 can also be used
for delivery of the hot compressed natural gas in accordance with
this embodiment of the invention, and vice versa.
[0028] The embodiment shown in FIG. 3 is identical to that shown in
FIG. 2 with the exception that the heat exchanger 60 collects waste
heat from the exhaust 62 and/or the engine block of the prime mover
26 via cooling conduits 64 which circulate engine coolant in a
manner well known in the art. In accordance with the invention, the
hot compressed natural gas output through conduit 30 by the
compressor 26 driven by the prime mover is diverted by diverter
line 38 through the heat exchanger 60 where it is further heated.
The choke or controller 40 governs the amount of hot compressed
natural gas that is returned to the well. Efficiency may be further
improved by use of the vortex tube 70, well known in the art.
Diverter line 38 provides hot compressed natural gas input to the
vortex tube 70. The vortex tube 70 separates the hot natural gas
into a hot natural gas component which is injected into the well
through an injector line 72 into the production tubing 15. The
diverter line 38 and the injector line 72 may be insulated using an
externally applied insulation 76 of any type well known in the
art.
[0029] The cold natural gas component output by the vortex tube 70
is returned via a cold natural gas return line 74 to the natural
gas distribution system (pipeline 34). Alternatively, the cold
natural gas component may be returned (as shown in dashed lines) to
the compressed natural gas conduit 30 and re-introduced into the
natural gas stream being delivered to the pipeline 34. If so, the
cold natural gas component cools the hot compressed natural gas
compressed by the compressor 26. A baffle 31, or the like, prevents
the cold natural gas component from entering the diverter line 38.
In this embodiment, the cooler 32 may not be required since the
cold natural gas from the vortex tube 70 reduces the temperature of
the hot compressed natural gas in the conduit 30. A check valve 78
controls the flow of natural gas through the cold natural gas
return line 74. Optionally, a separator 20' separates fluids from
the cold natural gas returning through the cold natural gas return
line 74. A fluid drain line 22' conducts the separated fluids to
the fluid tank 24. In this embodiment, the packer or centralizer 21
permits free movement of natural gas up the annulus between the
production tubing 15 and the casing 10.
[0030] FIG. 4 is a schematic diagram of yet a further embodiment of
the invention in which production from oil wells is facilitated by
continuously injecting heat generated by surface equipment used to
produce crude oil from the well. In accordance with this embodiment
of the invention, a surface pump such as a jack pumping system 102,
well known in the art, is driven by prime mover 104 to produce
crude oil 100 from a production zone 12 through a production tubing
15 in a manner well known in the art. A packer 21 isolates the
annulus between the casing 10 and the production tubing 15 from the
production zone. Pump jack system 102 reciprocates a downhole pump
105 in a manner well known in the art to produce oil up through the
production tubing 15. The pump jack 102 is driven by the prime
mover 104, which is frequently an electric motor, although internal
combustion engines are sometimes used, especially if the well also
produces natural gas.
[0031] Heat exchanger and recirculator 107 collects heat generated
by the prime mover 104 and transfers the heat to a heat transfer
medium. In this embodiment, a closed loop circuit is used to
continuously circulate hot compressed gas to heat the well system.
As is well known in the art, oil wells commonly produce some
natural gas along with the oil. This natural gas is commonly
referred to as "casing head gas", and it is frequently produced in
enough abundance to power the prime mover 104 as well as to provide
gas that can be re-injected into the well to heat the well. If the
well does not produce natural gas, it can be supplied in an
appropriate quantity from another source, or a gas such as carbon
dioxide, nitrogen or air can be supplied for use as the heat
transfer medium.
[0032] The heat exchanger and recirculator 107 circulates the hot
compressed gas through an injection line 108 which is optionally
connected to the input of a vortex tube 110. The heat exchanger and
recirculator 107 therefore provides a power source for continuously
injecting heated gas into the well. The vortex tube 110 separates
the hot compressed gas into a hot gas component output which is
circulated through a hot gas conduit 114 to an injection system 116
connected to a hollow sucker rod 120 using a flexible or
reciprocating conduit 118 connected to a top of the hollow sucker
rod 106. The heated compressed gas 120 is forced down a center of
the hallow sucker rod and through a check valve at a top of the
down hole pump 105. The hot compressed gas rises through the crude
oil in the production tubing string 15 as gaseous bubbles 124 of
hot gas which heat the oil to help keep paraffins, bitumens and
asphaltenes in suspension until they are produced from the well in
order to prevent obstruction of the production tubing 15. After the
hot gas has risen through the oil crude oil it returns via a return
line 130 to the heat exchanger and recirculator 107. In this
embodiment, the return line 130 is buried underground. Any or all
of the lines 108, 114 and 130 may be wrapped in insulation 76 as
explained above with reference to FIG. 3. If the vortex tube 110 is
used, a cold gas stream separated out by the vortex tube 110 is
returned via return line 112 to the heat exchanger and recirculator
107. An optional fuel supply line 113 may supply natural gas fuel
to a fuel intake of the prime mover 104, which uses a portion of
the casing head gas produced from the well.
[0033] The invention therefore facilitates production from both
natural gas and oil wells by continuously heating the well system.
Waste heat is thereby used for a useful purpose and dependence on
chemical additives and their associated maintenance is reduced. The
systems in accordance with the invention are low maintenance and
self regulating and can significantly improve production from wells
where hydrate plugs, paraffin deposits, or condensates inhibit or
stop production.
[0034] The embodiment(s) of the invention described above are
intended to be exemplary only. The scope of the invention is
therefore intended to be limited solely by the scope of the
appended claims.
* * * * *