Note: Descriptions are shown in the official language in which they were submitted.
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METHOD AND SYSTEM FOR INCREASING OIL PRODUCTION FROM AN OIL
WELL PRODUCING A MIXTURE OF OIL AND GAS
FIELD OF TEE IWENTION
This invention relates to a method for increasing oil production from oil
wells producing a mixture of oil and gas at an elevated pressure through a
wellbore penetrating an oil bearing formation containing an injection zone and
an
oil bearing zone by separating a portion of the gas from the mixture,
utilizing
energy from at least a portion of the mixture to compress at a surface the
separated
gas, and i.njecting the compressed gas into the injection zone.
BACKGROUND OF THE .T.NVENTION
In many oil fields the "oil bearing formation comprises a gas cap zone and
an oil bearing zone. Many of these fields prQduce a mixture of oil and gas
with
the gas to oil ratio (GOR) increasing as the field ages. This is a result of
many
factors well known to those skilled in the art. Typically the mixture of gas
and oil
is separated into an oil portion and a gas portion at the surface. The gas
portion
may be'marketed ns a naturat gas product, iniected to maintain pressure in the
gas
cap or the like. Furiher, many such fields are located in parts of the world
where it
is difficult to economically move the gas to market therefore the injection of
the
gas preserves its availability as a resource in the future as well as
maintaining
pressnre in the gas cap.
Wells in such fields may produce mixtures having, a GOR of over 10,000
standard cnbic feet per standard barrel (SCF/STB). In such instances, the
mixture
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may be less than 1% liqtuds by volume in the well Typically a GOR from 800 to
2,500 SCF/STB is more than sufficient to caizy the oil to the surface as a
gas/oil
mixture. Normally the oil is dispersed as finely divided droplets or a mist in
the
gas so produced. In many such wells quantities of water may be recovered with
the oil. The term "oil" as used herein refers to hydrocarbon liquids produced
from
a formation. The surface facilities for separating and retnrni.ng the gas to
the gas
cap obviously must be of substantial capacity when such mixtures are produced
to
return sufficient gas to the gas cap or other depleted foimations to maintain
oil
production.
Typically, in such fields, gathering lines gather the fluids into common
lines ivhich are then passed to production-.facilities or the like where crude
oil,
condensate, and other hydrocarbon liquids are separated and transported as
crude
oil. Natural gas liquids are then recovered from the gas stream and .
optionally
combined with the crude oil and condensate. Optionally, a miscible solvent
which
comprises carbon diomde, nitrogen and a mixture of light hydrocarbons such as
the gas stream may be used for enbanced oil recoveiy or the like. The
remaining
gas stream is then passed to a compressor where it is compressed for
injection.
The compressed gas is injected through injection wells, an annular section of
a
production well, or the like, into the gas cap.
Clearly the size of the surface equipment required to process the mixture of
gas and oil is considerable and may become a li.miting factor on the amount of
oil
which can be produced from the formation because of capacity limitations on
the
ability to liandle the prodimed: gas.
]t has been disclosed in U.S. Patent No. 5,431,228 "Down Hole Gas-Liquid
Separator for Wells" issued July 11, 1995 to Weingarten et al and assigned to
Atlantic Richfield Company that an auger. separator can, be used downhole to
separate a gas and liquid stream for separate recovery at the surface. A
gaseous
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poition of the stream is recovered through an annular space in the well with
the
liquids being recovered through a production tubing.
In SPE 30637 "New Desiffi for Compact Liquid-Gas Partial Separation:
Down Hole and Surface Installations for Artificial Lift Applications" by
Weingarten et al it is disclosed that auger separators as disclosed in U.S.
Patent
5,431,228 can be used for downhole and surface installations for gas/liquid
separation. While such separations are particularly useful as discussed for
artificial or gas lift applications and the like, all of the gas and liquid is
still
recovered at the surface for processing as disclosed. Accordizigly, the
siaface
equipment for processing gas may still impose. a signif cant limitation on the
quantities of oil which can he pror.iuced from a subterranean formation which
Produ6es oil as a mixture of gas and liquids.
Accordingly a continu.ing search has been directed to the development of
methods which can increase the amount of oil which may be produced from
subterranean formations producing a mixture of oil and gas with existing
surface
equipment.
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SUMMARY OF TIdE JNVENTION
Accotding to the present invention, it has been found that increased
quantities of oil can be produced from an oil well producing a mixture of oil
and
gas at an elevated pressure through a wellborepenetrating an oil-bearing
formation containing an oil-bearing zone and an injection zone, by separating
at
least a portion of the gas from the mixture of oil and gas to produce a
separated
gas and an oil-enriched mixture; utilizing energy from at least a portion of
the
mixture of oil and gas to compress at a surface at least a portion of the
separated
gas to produce a compressed gas having sufficieat pressvre to be mjected into
the
iniection zone; injecting the compressed gas into the iniection zone; and
recovering at least a major portion of the oil-entiched mixtvre.
The invention further comprises a system for increasing oil production from
an oil well producing a mixtvre of oil and gas at an elevated pressure through
a
wellbore penetrati.ng a formation containing an oil-bearing zone and an
injection
zone, wherein the system comprises a separator in fluid communication with the
oil-bearing zone; turbine positioned on the surface and having an inlet in
fluid
communication with the separator for receiving fluids from the separator for
driving
the turbine; and a compressor positioned on the surface, the compressor being
drivingly connected to the turbine and having a gas inlet in fluid
communication with
a separated gas discharge outlet on the separator, the compressor further
having a
compressed gas discharge outlet in fluid communication through a passageway
with
the injection zone.
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BRIEF DESCRIPTION OF THE DRAWINGS
Fig. 1 is a schematic diagram of a production well, according to the prior
art, for proc3ucing a mixture of oil and gas from a subterranean formation and
an
injection well for injecting gas back into a gas cap in the oil bearing
formation.
Fig. 2 is a schematic diagram of a downhole portion of an embodiment of
the system of the present invention in which gas is separated downhole from
liquids in a formation, produced through a production well to a surface where
it is
compressed, and injected through a dedicated injection well back into a gas
cap in
the formation;
Fig. 3 is a schematic diagram of a downhole portion of a portion of an
alternate embodi.ment of the system of the present invention in which gas is
separated dotivnhole from liquids in a formation, produced through a
production
well to a surface where it is compressed, and injected through another
production
tivell, acting as an injection well, back into a gas cap in the formation;
Fig. 4 is a schematic diagram of a downbole portion of an alternate
embodiment of the system of the present invention in which gas is separated
downhole from. liquids in a formation, produced through a production well to a
surface where it is compressed, and injected through an annulus of the
production
wel.l back into a gas cap in the formation;
Fig. 5 is a. scbematic diagram of a downhole portion of an alteznate
embodiment of the system of the present invention in which gas is separated at
a
surface from liquids produced from a formation, compressed, and iniected
through
the production well back into a gas cap in the formation;
Fig, 6 is a schematic flow diagram of a surface portion of an alternate
embodiment of the system of the present invention for compressing gas using
energy from an oil-enziched mixture of oil and gas;
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Fig. 7 is a. schematic flow diagzam of a suwrface portion of an alternate
embodiment of the system. of the present invention for compressing gas using
enerU from gas from an oil well;
Fig. 8 is a schematic flow diagram of a surface portion of an alternate
embodiment of the system of the present invention for compressing gas using a
beater;
Fig. 9 is a schematic flow diagram of a surface portion of an alternate
embodiment of the system of the present invention for compressing gas using
energy derived from an external source; and
Fig. 10 is a schematic flow diagram of a surface portion of an alternate
embodiment of the system of the present invention for compressing gas using
energy derived from an external. source.
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DESCRIPTION OF THE PREFERRED EMBODIMENTS
In. the discussion of the Figures, the same numbers will be used to refer to
the same or similar components throughout. Certain components of the wells
necessary for the proper operation of the wells, and certain pumps, val,ves,
and
compressors necessary to achieve proper flow of fluids, have not been
discussed in
the interest of conciseness.
In Fig. 1, depicting the prior art, a production oil well 10 is positioned in
a
wellbore (not shoNvn) to extend from a surface 12 through an overburden 14 to
an
oil bearing formation 16. The production oil wel110 includes a first casing
section
18, a second casing section 20, a third casing section 22, and a fourth casing
section 2A, it being understood that the oil well 10 may alternatively include
more
or fewer than foitr casing sections. The use of such casing sections is well
lmown
to those sId]led in the art for the completion of oil wells. The casings are
of a
decreasing size and the fourth casing 24 may be a slotted liner, a perforated
pipe,
or the like. While the production oil well 10 is shown as a well Nvhich has
been
curved to extend liorizontally into the formation 16, it is not necessary that
the
well 1.0 include such a horizontal section and, alternatively, the well 10 may
extend only vertically into the formation 16. Such variations are well known
to
those sldlled in the art for the production of oil from subterranean
forinations.
The oil well 10 also includes a tubing string referred to herein as production
tubing 26 for the production of fluids from the well 10. The production tubing
26
extends upwardly to awel.lhead 28 shown schematically as a valve. The wellhead
28 conta.ins the necessary valving and the like to control the flow of fluids
into and
from the oil well 10, the production tubing 26, and the like.
The formation 16 includes a selected injection zone 30 and an oil bearing
zone 32 underlying the iniection zone 30. The selected injection zone 30 may
be a
gas cap zone, an aqueous zone, an upper portion of the oil bearing zone 32, a
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depleted portion of the formation 16, or the like. Pressure in the formation
16 is
maintained by gas in the injection zone 30 and, accordingly, it is desirable
in such
fields to maintain the pressuse in the injection zone -as hydrocarbon fluids
are
produced from the formation 16 by injecting gas. The formation pressure may be
maintained by water injection, gas injection, or both_ The injection of gas
requires
the removal of the liquids from the gas prior to compressing the gas, and
injecting
the gas back into the injection zone 30. Typically, the GOR of oil and gas
mixtures recovered from such formations increases as the level of the oil
bearing
zone drops as a result of the removal of oil from the oil bearing formation
16.
In the well 10, a packer 34 or a nipple with a Iocking mandrel or the like is
iised to prevent the flow of fluids in the annulai space between the third
casing
section 22 and the fourth casing section 24. A packer 36 is positioned to
prevent
the flow of fluids in the annular space between the exterior of the production
tubing 26 and the interior of the second casin,g section 20 and that portion
of the
interior of the third casing section 22 above the packer 36. Fluids from the
fornuataon 16 can thus flow upwardly through the production tubing 26 and the
wellhead 28 to processing equipment (not s.hown) at the surface, as described
previously. The well 10, as shown, produces fluids under the formation
pressure
and does not require a pump.
Also shown in Fig. 1 is an injection well 40 comprising a first casing
section 42, a second casing section 44, a third casing section 46, and an
injection
tubing 4 S. A packer 50 is positioned between the interior of the casing 44
and the
exterior of the tubing a 8 to prevent the upward flow of fluid between the
tubing 48
and the casing 44. Gas is injected into the injection zone 30 through
perforations
52 in the third casing section 46. The flow of gases into the we1140 is
regulated
by a wellhead 53 shown schematically as a valve,
In operation, gas produced from the well 10 is injected into the injection
zone 30 through the injection wel140, The injected gas thereby maintains
pressure
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in the formation 16 and remains available for production and use as a fuel or
other
resource at a later date if desired.
In oil wells which produce excessive amounts of gas, the necessity for
handling. the large volume of gas at the surface can limit the ability of the
formation to produce oil. The installation of sufficient gas handling
equipment to
separate the large volume of gas from the oil for use as a product=, or for
injection
into the injection zone 30 can be prohibitively expensive.
In. Fig. 2, an embodiment of a downhole portion of the present invention is
shown which permits the downhole separation and injection of at least a
portion of
the produced gas, and which permits the produetion of an oil-enriched mixture
of
oil and gas. An embodiment of a suiface portion of the present invention,
which
surface portion is complementary to the downhole portion, is described below
with
respect to Figs. 6-10 in which surface facilities compress gas separated in
the
doNvnhole portion of the present invention before the gas is injected using
the
downhole portiorL
The embodiment shown in Fig. 2 comprises a modification of the
production oil well 10 in which a perforated or punched orifice, opening, or
hole,
such as the hole 60, is formed in the production tubing 26 in a manner well
known
to those skilled in the art. The hole 60 may optionally include a valve (not
shown), such as a gas lift valve, a check valve, a hole insert, or the like,
positioned
tlierein for controlling the flow of fluids therethrough. A downhole separator
70 is
positionecl within the production t bing 26 so' that a gas discharge outlet
(not
shown) on the separator is aligned with the hole 60 for discharge
therethrough.
The separator 70 may be any of a number of different types of separators, such
as
an auger separator, a cyclone separator, a rotary centrifugal separator, or
the like.
Auger separators and the positioning of them in production tubing are more
fully
disclosed and discussed in U.S. Patent No, 5,431,228, "Down Hole Gas Liquid
Separator for Wells", issued July 11, 1995 to Jean S. Weingarten et al, and in
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"New Design for Compact-Liquid Gas Partial Separation: Do'Tvn Hole and Surface
Installations 1'or Artificial Lift Applications", Jean S. Weingarten et al,
SPE 30637
presented October 22-25, 1995. Such separators and the positioning of them
dotivnhole are considered to be well lnown to those sidlled in the art and are
effective to separate at least a major portion of the gas from a flowing
stream of
liquid (e.g., oil) and gas by causing the fluid mixture to flow around a
circular path
thereby forcing beavier phases, i.e., the liquids, outwardly by centrifugal
force and
upwardly into the production tubing 26 for recovery at the surface 12, The
fighter
pbnses of the nnixture, i.e., the gases, are displaced inwardly within the
separator
70, away from the heavier phases, and are thereby separated from the liquids,
and
flow from the separator 70 through the separator gas outlet- the hole 60, and
upwardly through an annuins 72, formed between the second casing section 20
and the production t bing 26, to the snrface 12.
As shoNvn schematically in Fig. 2, an oil-eniiched mixture line 80 and a gas
line 82 are connected for providing fluid commuaication between the welihead
28
and the annulus 72, respectively, and surface facilities configured for
compressing
the gas as will be described more fully belotiv with respect to Figs. 6-10. A
gas
return line 84 is connected for providing fluid commuuication between a
discharge
out]et of surface facilities and the injection tubing 4.8.
In the operation of the system shown in Fig. 2, a mixture of oil and gas
(which may also include other liquids, such as water) flows from the oil-
bearing
formation 32 through the fourth and third casing sections 24 and 22,
respectively,
into the production tubing 26, and into the separator 70, as shown
schematically
by arrows 90. The separator 70 separates at least a portion of the gas from
the
mixture of oil and gas in the oil well 10 to produce a separated gas and -an
oi].-
enriched mixture. As showu schematically by arrows 92, the oil-enriched
mixture
produced by the separator 70 is discharged upwardly into the production tubing
26
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and through the wellhead 28 and the oil-enriched mixture line 80 to sunface
facilities described below. As shown schematically by an arrow 94, the
separated
gas is discharged from the sepaiator 70 through the hole 60 into the annulus
72.
The separated gas then flows upwardly throuoh the annulus 72 and the gas line
82
to surface facilities, described below, which compress the gas to a pressure
suiTicient to permit the gas to be injected into & injection zone 30, such
pressure
being referred to hereinafter as an "injection pressure". The gas compressed
to the
injection pressure by the surface facilities is discharged from the surface
facilities
through the gas return line 84 into the injection tubing 48 in the well 40, as
shown
schematically by an arrow 96, and into the injection zone 30. - As a result of
head
pressure and friction losses which are incurred as the gas is injected
downhole, the
foregoing injection pressure preferably exceeds the pressure-.of the gas in
the
injection zone 30, less the head presslire of the gas in the injection tubing
48, plus
pressure loss incurred from friction as the gas is injected downhole.
While only one well 10 is depicted in Fig. 2, a plurality of wells similar to
the well 10 may produce gas which is compressed by surface facilities and
injected through the dedicated i.njection well 40 into the injection zone 30.
In an alternate embodiment of the system shown in Fig. 2, the separator 70
may be provided with a cross-over device (not shown), well lrnown to those
skilled in the art, to direct separated gas from the separator to the
production
tubing 26 rather than the annulus 72, and to direct the oil-enriched mixture
from
the separator to the annulus 72 rather than the production tubing 26. The oil-
enriched m.i.xture line 80 would then be connected in fluid communication with
the
annulus 72 rather than the production tubing 26, and the gas line 82 would be
connected in fluid communication with the production tubing 26 rather than the
annulus 72. Operation of such an alternate embodiment would otherwise be
substantially similar to the operation of the embodiment shown in Fig. 2.
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By the use of the system shown in Fig. 2, a portion of the gas is separated
downhole from the oil/gas mixture and, as a result, the separated gas incurs
less
head loss and less ~riction loss and, therefore, maintains a substantially
higher
pressure as it is produced to the surface, than it would if it were produced
in
combination with the oiI/gas mixture. The downhole separation of the gas from
the oil/gas mix:ture also relieves the load on surface facilities to separate
gas from
the oil/gas mixture. In many fields, it is not uncommon to encounter GOR
values
as high as 10,000 SCF/STB. GOR values from 800 to 2,500 SCF/STB are
generally more than sufficien.t to carry the produced liquids to the surfaee.
A
signi.ficant amount of the gas can thus be separated downhole with no
detriment to
lhe production process. '1Ms significantly increases the amount of oil which
can
be recovered from formations which produce gas and oil in -mixture which are
limited by the amount of gas handling capacity available at the surfaee.
Additionally, the system of Fig. 2 facilitates the measurement of the gas
separation
effieiency and of the composition of gas injected downhole.
In Fig. 3, an alternate embodiment of the system of Fig. 2 is shown. An
additional bole 62, similar to the hole 60, is perforated, punched, or
otherwise
formed in the production tubing below the separator 70 and a- valve (not
shown),
such as a gas lift valve, a check valve, a hole insert; or the like, is
positioned
therein for controlling the flow of fluids therethrough in a manner well known
in
the art. A. tiibing tail extension 1.00 is set in a. lower end 26a of the
production
tiibing 26. A packer 102 is positioned between the tubing tail extension 100
and
the production tubing 26 to prevent fluid cornmiuiication therebetween, and a
packer 104 is interposed between the tubing tail extension 100. and the third
casing
section 22 to prevent fluid communication therebetween. A confined annular
space 106 is tUiis defined between the tubing tail extension 100 and the third
casing section 22 and between the packers 36, 102, and 104. The third casing
section 22 is perforated with perforations 108 to provide fluid communication
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between the injection zone 30 and the annular space 106. The tubing tail
extension 100 is fitted with a first check valvt 110 suitably positioned to
permit
Iluid to flow only from the tubing tail extension 100 to"the annular space 106
and,
therefore, to prevent contra flow. The tubing tail extension 100 is fitted
with a
second check valve 112 suitably positioned to permit fluid to flow only from
that
portion of the third casing 22 below the packer 104 to the tubing tail
extension 100
and, therefore, to prevent icontra flow. The positioning of the tubing tail
extension
100, the packers 102 and 104, and the check valves 110 and 112 is considered
to
be well known to those skilled in the art and therefore will not be discussed
further.
As further shown in Fig. 3, in place of the well 40 (Fig. 2) is a well 10'
which is substantially identical to the well 10, except for its location in
the
format.ion. 16. A il components nf the well 10' are identified by the same
reference
numera.ls as the components of the well 1.0, except that the reference
numerals for
the well 10 are primed. Because of the substantial similarity of the wells 10
and
10', no further discussion of the well 10' is considered necessazy. It is
noted
though that the gas return line 84 is connected in fluid communication with
the
annulus 72' of the well 10'.
In the operation of the system shown in Fig. 3, in which the well 10 is
operable as a production well and the well 10' is operable as an injection
well, a
mixture of oil and gas flows from the oil-bearing foimation 32 through fourth
and
third casing sections 24 and 22, respectively, through the second check valve
112
and the tubing tail extension 100, into the production tubing 26, and into the
separator 70, as shown schematically by the arrows 90. The valve positioned in
the hole 62 prevents the mixttlre of oil and gas from flowing through the hole
62
into the annttlus 72. The separator 70 separates at least a portion of the gas
from
the mi:xture of oil and gas in the oil well to produce a separated gas and an
oil-
enriched mi;cture. As shown schematically by the arrows 92, the oil-enrriched
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mixture produced by the separator 70 is discharged upwardly into the
production
tubing 26 and through the wellhea.ci 28 and the oil-enriched mixture line 80
to the
surface facilities described below, As shovyn schematically by the arrow 94,
separated gas is discharged from the separator 70 through the hole 60 into the
annulus 72. The' separated gas then flows upwardly through the annulus 72 and
the gas line 82 to surface facilities which compress the gas to the injection
pressure, defined above. As shown schematically by the arrow 96, compressed
gas is discharged from the surface facilities through the gas return line 84
into the
annulus 72' of the well 10' and through the hole 62' into the production
tubing 26.
The gas in the production tubing 26' flows through the tubing tail extension
100',
the check valve 110', and into the injection. zone 30; and the check valve
112'
prevents the flow of the gas into the oil-bearing formation 32.
While only one well 10 and only one well 10' is depicted in Fig. 3, one or
more wells similar to the well 10 may produce gas which is compressed by
surface
facilities and injected through one or more wells similar to the injection
well 10'
into ttie injection zone 30. Furthermore, wells may alternately be used as
production wells and, during their production off-cycles, as injection wells.
For
example, the well 10 shown in Fig. 3 may be used as an injection well during
its
production. off-cycle while the well 10' is used as a production well which
produces gas which is injected into the well 10.
In an alternate embodiment of the system shown in Fig. 3, the separators 70
and 70' may be provided with a cross-over device (not shown), well known to
those skilled in the art, to direct separated gas from the separator to the
production
tubing 26 or 26' rather than the annulus 72 or 72', and to direct the oil-
enriched
mixture from the separator to the annulus 72 or 72' rather than the production
tubing 26 or 26'. The oil-enriched rnixture line 80 would then be connected in
fluid communication with the annulus 72 rather than the production tubing 26,
and
the gas line 82 would be connected in fltiid communication with the production
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tubing 26 rather than the annulus 72. Operation of such an alternate
embodiunent
,arcmld othenNise be substantially similar to the operation of the embodiment
shown. in Fig. 3.
By the use of the system shown in Fig. 3, not only is a portion of the gas
separated downhole from the oil/gas mixture, and the gas pressure thereby
substantially maintained, and the measurement of the separation efficiency and
injection gas composition facilitated as with the system of Fig. 2 but;
additionally,
the system of Fig. 3 does not require a dedicated injection well to inject gas
downhole. The system of Fig. 3 permits production we11s to be utilized more
efficiently since they may be used as injection wells during their production
off-
cycle.
In Fig. 4, a modified portion of an alternate enmbodiment -of the system of
Fig. 2 is shown. The separator 70 is positioned in a tubular member 120
positioned in a]otiver end. 26a of the production tubing 26. The positioning
of
tubular members by wire line operations or coiled tubing is well known to
those
skilled in the art and will not be discussed, A packer 122 or a nipple with a
locking mandrel or the like is positioned above the hole 60, and between an
upper
end 120a of the tubular member 120 and the production tubing 26 to control the
flow of fluids through a"straddle-by-tubing" annulus 124 defined between the
tubular member 120 and that portion of the production tubing 26 extending
below
the packer 122. A packer 126 is positioned below the packers 36 and 122
between
a lower end 120b of the tubular member 120 and the third casing section 22 to
control the flow of fluids in a confined annular space 128 defined between the
tubular member 120 and the third casing section 22 and between the packers 36,
122, and 126. The third casing section 22 is perforated with perforations 130
to
provide tluid communication bet reen. the injection zone 30 and the annular
space
.128. A. coiled tnbi.ng 132 is positioned in the production tubing 26 for
providing
fluid communication between a gas outlet 70a of the separator 70 and a gas
line 82
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to surface facilities described below. A "coil-by-tubing" annulus 134 defined
between the production tubing 26 and the coiled tubing 132 provides fluid
communication between an oil-enriched mixture outlet'70b of the separator 70
and
the oil-enriched mixture line 80 to surface facilities. The gas return line 84
is
connected in fluid communication between the surface facilities and the
annulus
72 (refe,rred to, with reSPect to Fig. 4, as a "tubing-by-casing" annulus) for
carrying to the annulus 72 compressed gas for injection into the formation 16.
In the operation of the system shown in Fig. 4, a mixture of oil and gas
flows from the oil-bearing formation 32 through the fourth and third casing
sections 24 and 22 (Fig. 2), respectively, into the tubular member 120 and
into the
separator 70, as shoNvn schematically by the arrows 90. The separator 70
separates
at least a portion of the gas from the mixture of oil and gas in the oil well
to
produce a separated gas and an oil-enriched mixture. As shown schematically by
the arrows 92, the oil-enriched mixture produced by the separator 70 is
discharged
upward.ly through the outlet 70b, the coil-by-tubing annulus 134, the wellhead
28
(Fig. 2), and the oil-enriched mixture line 80 to surfaee facilities descrnbed
below.
As shown schematically by the arrow 94, the separated gas produced by the
separator 70 is discharged upwardiy through the gas outlet 70a, the coiled
tubing
132, the gas line 82, and to surface facilities whiah compresses the gas to
the
injection pressure, defined above. Compressed gas is discharged from the
surface
facilities through the gas retvrn line 84 into the tubing-by-casing annulus
72. As
shown schematically by the arrow 96, compressed gas in the tubing-by-casing
annulus 72 is ported through the hole 60 into and through the straddle-by-
tubing
annuliis 124, the annular space 128, the perforations 130, and into the
injection
zone 30.
ln an alternate embodiment of the system shown in Fig. 4, the separator 70
may be provided ivith a cross-over device (not shown), well lanown to those
skilled in the art, to direct separated gas from the separator to the annulus
134
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rather than the tubing 132, and to direct the oil-enriched mixture from the
separator to the tubing 132 rather than the annulus 134. The oil-enriched
mixture
line 80 would then be connected in fluid communicZtion with the tubing 132
rather than the annulus 134, and the gas line 82 would be connected in fluid
communication to the annulus 134 rather than the tubing 132. Operation of such
an alternate embodiment would otherwise be substantially similar to the
operation
of the embodiment shown in Fig. 4.
In a:fruther alternate embodiment of the system shown in Fig. 4, the system
may be configured without the tubular member 120, the packers 122 and 126, and
the hole 60 by replacing the packer 126 with the packer 36 and extending the
production tubing 26 to and through the packer 36. Operation of such an
alternate
embodiment is substantially similar to the operation of the emhodiment shown
in
Fig. 4, except that the mixture of oil and gas flows through te production
tubing
26 without flowing through the tubular member 120, and compressed gas flows
through the annulus 72 to the injection zone 30 without flowing through the
hole
60 and through the annulus 124.
By the use of the system shown in Fig. 4, not only is a portion of the gas
separated downhole from the oil/gas mixture, and the gas presstire maintained,
and.
the measurement of the separation efficiency and injection gas composition
facilitated as with the system of Fig. 2 bufi, additionally, the system of
Fig. 4 does
not require an additional well to inject gas downhole and, thus, does not
require a
significant quantity of piping and valves at the surface to interconnect
various
wells.
In Fig. 5, an altennate embodiment of the system of Fig, 4 is shown in
which the separator 70 is positioned at the surface 12. Because there is no
downhole separation of the gas from the oil and gas produced, no coiled tubing
is
run down the production tubing 26 as there was in the system of Fig. 4. The
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system shown in Fig. 5 is otherwise substantially similar to the system shown
in
Fig. 4.
Operation of the system of Fig. 5 is similar to the operation of the system of
Fig. 4 except that oil and gas produced from the formation 16 is separated by
the
separator 70 positioned at the surface 12, Thus the arrows 90 represent the
flow of
a ini.Yture of oil and gas from the oil-beari.nd formation 32 through fourth
and third
casing sections 24 and 22, respectively, through the tubular member 120 and
the
production ttibing 26, and into the separator 70 located at the surface 12.
The
separator 70 separates at least a portion of the gas from the mixture of oil
and gas
in the oil weU to prodnce a separated. gas and an oil-enriched mixture. The
oil-
enricbed mixtlire produced by the separator 70 is discharged through the
outlet
70b into the oil-enriched mixture line 80 to surface facilities described
below.
Separated gas produced by the separator 70 is discharged through the gas
outlet
70a and the gas line 82 to surface facilities which compress the gas to the
injection
pressure, defined above. Compressed gas is discharged from the surface
facilities
through the gas return line 84 into the annulus 72. As shown schematically by
the
arrow 96, compressed gas in the annulus 72 is ported through the hole 60 into
and
through the annulus 124, the annular space 128, the perforations 130, and into
the
injection zone 30.
In an alternate embodiment of the system shown in Fig. 5, the system may
be configured without the tubular member 120, the packers 122 and 126, and the
hole 60 by replacing the packer 126 with the packer 36 and extending the
productl'on t bing 26 to and through the packer 36. Operation of such an
alternate
embodiment is substantially similar to the operation.of the embodiment shown
in
Fig. 5, except that the mixture of oil and gas flows through the production
tubing
26 without flowing through the tubular member 120, and compressed gas flows
through the annulus 72 to the injection zone 30 without flowing through the
hole
60 and through the annulus 124.
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By the use of the system shown in Fig. 5, the separator 70 is more
accessible t:han it was in the foregoing systems described, no coiled tubing
is
recluired, and the well ] 0 permits wireline tools to pass'therethrough. As
with the
foregoing systems, the separation efficiency and injection gas composition may
be
measured, Furthermore, an additional well is not required to inject gas
downhole.
Thus, a si~ificant quantity of piping and valves is not required at the
surface to
interconnect various wells.
In Figs. 6-10, five embodiments of a surface portion of the present
invention are shown in which gas, after it has been separated and before it is
injected downhole, is compressed using surface facilities referenced in the
foregoing disciission of embodiments of the downhole portion of the present
invention sboivn in Figs. 2-5. As stated previously, the surface portion of
the
present invention is complementary to the downhole portion and, in the
following
disc ssion, the embodiments of the slrr.face portion are to be understood as
connect-ed. throiIgh the oil-enriched mixture line 80, the gas line 82, and
the gas
return line 84 to any one of the embodiments of the d.ownhole portion
described
with respect to Figs. 2-5.
The embodiment of the surface portion of the present invention shown in
Fig. 6 comprises a suitable compressor 200 drivingly connected through a shaft
202 to a suitable tvrbine 204. The compressor 200 is connected to the gas line
82
for receiving gas therethrough, and to the gas retan line 84 for discharging
gas
thereto. The compressor 200 may be an axial, radial, or mixed-flow compressor,
or the like, configured for compressing gas received through the gas line 82
to the
injection pressure, defmed above, and for discharging compressed gas to the
gas
return line 84. Compressors such as the compressor 200 are considered to be
well
known to t.hose ski.lled in the art and Nvil.l not be discussed fitrther.
The t rbine 204 is connected in parallel with the oil-enriched mixture line
80 for receiving through a line 80a, and for being driven by, at least a
portion of
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the oil-enriched mixture flowing through the oil-enriched mixture line 80, and
for
discharging the received mixture through a line 80b to the oil-eniiched
mixture
line 80. A suitable valve 206 is positioned in the oil-enriched mixtare Iine
80
between the line 80a and 80b for controlling the amount of the oil-enriched
mixture which flows through the turbine 204. The turbine 204 may be a radial
or
axial turbine such as a turbine expander, a hydraulic turbine, a bi-phase
turbine, or
the h1ce. Turbine expanders, hydraulic tarbines, and bi-phase turbines are
considered to be well known to those slo7led in the art, and are effective for
receiving a. stream of fluids, such as the oil-enriched mixture in the present
invention, and for generating, from the received stream of fluids, torque
exerted
onto a shafk such as the shaft 202, such stream of fluids comprising largely
gases,
liquids, and. mixtures: of gases and liquids, respectively. Bi-phase turbines;
in
particular, are more fu]Iy disclosed and discu.ssed in U.S. Patent No.
5,385,446,
entitled "Hybrid Two-Phase Turbine' , issued January 31, 1995, to Lance G.
Hays.
In the operation of the system shown in Fig. 6, if the valve 206 is open,
then the oil-enriched mia.-ture flows through the oil-enriched mixture line
80,
generally bypassing the turbine 204, to a pipeline (not shown)'which carries
the
mixture to downstream processing facilities (not shown) which are aonsidcred
to
be well known in the art and wiIl not be discussed. tiVhen the turbine 204 is
bypassed by the oil-eniiched mixture as a result of the valve 206 being open,
the
turbine 204 does not drive the compressor 200' and gas in the gas line 82 is
not
compressed and cannot be injected into the formation 16 (not shown). If the
valve
206 is closed, then all of the oil-enriched mixture flowing through the oil-
enriched
mixture line 80 also flows through the line 80a to and through the t-Jrbine
204, and
through the line 80b to the pipeline (not shown) which carries the mixture to
doivnstream processing facilities. As the mixture flows through the turbine
204,
rotational motion is imparted to the turbine which then imparts rotational
motion
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to the sha$ 202 and drives the compressor 200. The compressor 200 receives gas
through the gas line 82 and, as the compressor rotates, it compresses the gas
received from the line 82 to the injection pressure, defined above. Compressed
gas is discharged from the compressor 200 into the gas retuin line 84 and into
the
injection zone 30 (Figs. 2-5) as discussed above. The valve 206 may be only
partiaIly closed to direct only a porfion of the oil-eniiched mixture to the
turbine
204 in which case, the pressure imparted by the compressor 200 to gas received
through the gas line 82 wi]1 be related to the amount that the valve 206 is
closed.
Preferably, the valve 206 is closed only enough to permit the compressor 200
to
sufficiently compress gas for injection into the formation, and to thereby
conserve
pressure in the mixture in the oil-enricbed. mixture line 80.
By the use. of the. foregoing system shown in Fig. 6, formation pressure may
be used to inexpensively compress gas at a well and inject the gas downhole
without the necessity of sending the gas to a central compressor plant.
In Fig. 7, an alternate embodiment of the system of Fig. 6 is shown in
which the turbine 204 is driven by at least a portion of the gas taken off of
the gas
line 82 rather than at least a portion of the oil-enriched mixture taken off
of the oil-
enriched mixture line 80. To that end, a line 82a is connected for providing
fluid
communication between the gas line 82 and an inlet (not shown) to the turbine
204. A valve 210 is positioned in the gas line 82 downstream of the line 82a
take-
off for controlling the distribution of gas flow between the compressor 200
and the
turbine 204. The line 80b is connected for providing fluid communication
between an outlet (not shown) of the turbine 204 and the oil-enriched mixture
line
80.
ln the operation of the system shown in Fig. 7, the oil-enriched mixture
flows through the oil-enriched mixture line. 80 directly to a pipeline (not
shown)
which carries the mixture to downstream- processing facilities which are
considered to be well known in the art and will not be discussed. The valve
210 is
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actuated to regulate the flow of gas delivered from the gas line 82 to the
turbine
204 and to the compressor 200 so that a proper flow balance may be maintained
to
perrniit the turbine to generate the power required to drive the compressor,
thus
controlling the operation thereofl Therefore, proper operation of the system
of
Fig, 7 requires that the valve 210 *be neither fully open nor fully closed but
rather
that it be only partially open so that a portion of the gas in the gas line 82
be
directed to the compressor 200 and a portion be directed through the line 82a
to
the turbine 204. Gas that does not flow through the valve 210 drives the
turbine
204 which drives the compressor 200, and gas that flows through the valve 210
is
compressed by the compressor 200. The proportion of gas that flows through the
turbine 204 is preferably optimized to pernut the turbine 204 to drive the
compressor 200 to compress gas that flows through the valve 210 to the
injection
pressure, defined above. Gas is discharged from the tnrbine-204 through the
line
80b to the oil.-eririched mixture line 80 and to the pipeline and downstream
processing facilities (not shown); and compressed gas is discharged from the
compressor 200 into the gas return li.ne 84 and into the injection zone 30
(Figs. 2-
5) as discussed above.
In Fig. 8, an alternate embodiment of the system of Fig. 6 is shown. The
gas Iine 82 is connected for carrying gas to a separator 220, such as a
suction
scrubber or the like, configiired for producing a separated gas and a
separated.
liquid from the gas received through the gas line 82. A line 222 is connected
to
the separator 220 for cairying the separated gas produced by the separator 220
to
the compressor 200, and a line 224 is connected to the separator 220 for
cariying
separated liquids produced by the separator 220 to a line 226, a line 228, and
to a
pipeline (not shown), A line 230 carries a portion of the gas in the line 222
to a
heater such as a gas fired fiirnace 232 for combustion therein. While not
shown, it
is understood that suitable valves and the like are provided on the lines 222
and
230 for controlling gas flow distribution through those lines in a manner well
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known to those skilled in the art. A line 234 is connected for carrying
compressed
gas discharged from the compressor 200 to a gas-to-gas heat exchanger 236, and
the gas return line 84 is connected for canyin.g the coinpressed gas from the
heat
exchauger 236 to an injection well as discussed above,
The oil-eniiched mixture line 80 is connected for canying the oil-enriched
mi,Yture to a separator 240, such as an expander suction separator or the
like,
configured for producing a. separated gas and a separated liquid from the oi1-
enriched mixture received through the oil-enriched mixture line 80. A line 242
is
connected to the separator 240 for carry.ing the separated gas produced by the
separator 240 to the heat exchanger 236, and a line 226 is connected to the
separator 240 for canying separated liquids produced by the separator 240 to
the
line 228, and to the pipeline (not shown). A line 244 is comected to the heat
exchanger 236 for carlying the separated gas produced by the separator 240
from
the heat exchanger 236 to the furnace 232 for heatin.g therein. A line 246 is
connected for canying the separated gas produejed by the separator 240 and
heated
in the furnace 232 to an inlet (not shown) of the turbine 204. The line 228 is
connected for cariying gas from the turbine 204 to the pipeline. (not shown).
In the operation of the system shown in Fig. 8, the oil-enriched mixture
flows through the oil-enriched mixture line 80 to the separator 240 which
produces
a separated gas and a separated liquid. The separated liquids (i.e., oil-
enriched
mixture) flow through the lines 226 and 228 to the pipeline and downstream
processing facilities. The separated gas produced by the separator 240 flows
through the line. 242 to the heat exchanger 236, which transfers heat to the
separated gas, through the line 244 to the furnace 232, which further heats
the
separated gas,.and through the line 246 to the turbine 204. The heated gas
drives
the turbine 204, which then. drives the compressor 200, and the gas is then
discharged from the turbine through the line 228 to the pipeline (not shown).
The
beat transferred throligh the heat exchanger 236 and by the heater 232 to the
gas
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that drives the turbine 204 should be sufficient to maintain a temperature of
that
gas, as it is discharged' from the turbine, -which is high enough to prevent
paraffin's
andlor hydrates from forming in the gas.
Gas in the gas line 82 flows to the separator 220 which produces from the
gas separa.ted gas and separated liquids. The separated liquids produced by
the
separator 220 flow through the lines 224, 226, and 228 to the pipeline (not
shown)
and to downstream processing facilities. A portion of the separated gas
produced
by the separator 220 flows through the line 222 to the compressor .200,. and
another portion of the separated gas flows.through the lines 222 and 230 to
the
fiunace.232. The gas canied to the fiunace tlvrough the line 230 is combusted
to
generate heat.to heat the gas which flows from the line 244 to the furnace.
The
gas carried through the line 222 to the compressor 200 is- compressed to the
injection pressure, defined above. Compressed gas is then discharged from the
compressor 200 throirgh the line 234 to the heat exchanger 236 which
tran.zfers
heat froin the compressed gas carried by the line 234 to the separated gas
carried
by the line 242. The compressed gas is then carried by the gas return line 84
to an
injection well (not shown) for injection into the injection zone 30 (Figs. 2-
5) as
discussed above.
While the furnace 232 is depicted as a gas fired furnace, any suitable heater
may be used. For example, if electricity is available, an electric heater
could also
be utilized in lieu of the gas fired heater 232, and thereby conserve fuel gas
and
permit a greater quantity of gas to be compressed and injected into the
injection
zone 30 (Figs. 2-5).
In Fig. 9, an alteznate embodiment of the system of Fig. 8 is shown wherein
the compressor 200 is a first stage compressor.. The line 234 (Fig. 8) is
depicted in
Fig. 9 as two lines 234a and 234b, and a suitable second stage compressor 250
is
interposed between the lines 234a and.234b to further compress gas discharged
from the compressor 200 before the gas is passed through the heat exchanger
236
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and to the gas retium ]ine 84. The second stage compressor 250 is driven by
any
available suitable power source 252, such as an electrically powered motor, a
gas
fired turbine, a diesel engine, a turbine driven by fluids taken from
available high
pressure/output flowlines, or the hke. Because the compressor 250 adds heat to
the compressed gas, which heat is transferred via the heat exchanger 236 to
the gas
carriec3 to the ti.irbine 204, the fiunace 232 utilized in the system of Fig.
8 is not
utilized in the system of Fig. 9.
In the opesation of the system shown in Fig. 9, the oil-enriched mixttm
flms through the oil=enriched m;ix-ture Ii.ne 80 to the separator 240 which
produces
a separated gas- and a separated liquid. The separated liquids (i. e., oil-
enriched
mixture) flow through the lines 226 and 228 to the pipeline and downstream
processing. facilities. The separated gas produced by the separator 240 flows
through the line 242 to the heat exchanger 236, which transfers heat to the
separated gas, and through the line 246 to the turbine 204. The heated gas
drives
the turbine 204, Which then drives the compressor 200, and the gas is then
discharged ffrom the turbine through the line 228 to the pipeline (not shown).
The
heat transferred from the heat exchanger 236 to the gas that drives the
turbine 204
shonld be snfficient to maintain a temperature of that gas, as it is
discharged from
the tlirbine, which is high enough to prevent paraffin's and/or hydrates from
forming in the gas.
Gas in the gas line 82 flows to the separator 220 which produces from the
gas separated gas and separated liquids. The separated liquids produced by the
separator 220 flow through the lines 224, 226, and 228 to the pipeline and to
downstream processing facilities (not shown). The separated gas produced by
the
separator 220 flows through the line 222 to the compressor 200, and through
the
line 234a to the second stage compressor 250. The compressors 200 and 250
compress the gas to the injection pressure, defined above, and, as a
consequence of
the compression, the gas is also heated. The second stage compressor 250
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discharges the compressed and beated gas through the line 234b to the heat
exchanger 236 which transfers heat from the, compressed and heated gas to the
separated gas produced by the separator 240. The cornpressed gas is then
carried
from the heat exchanger 236 by the gas return line 84 to an injection well
(not
shown) for injection into the injection zone 30 (Figs, 2-5) as discussed
above.
In Fig. 10, an alteznate embodiment of the system of Fig. 9 is shown in
which a different separation technique is used. To that end, the oil-enriched
mixture line 80 is connected directly to the pipeline (not shown) for canying
the
oil-enriched mixture to downstream processing facilities (not shown). The gas
line 82 is conneeted for canying separated gas directly to the heat exchanger
236,
and the line 246 is connected for canrying- the separated gas discharged from
the
heat exchanger to the inlet (not shown) of the turbine 204. The outlet (not
shown)
of the turbine 204 is connected through a line 254 for carrying gas discharged
from the turbine to a separator 256, such as an auger separator, a cyclone
sepaialor, a rotary centrifuga.l separator, or the like, similar to the
separator 70
described above with respect to Figs 2-5. The separator 256 is configured for
separating at least a portion of the gas from the mixture of gas and liquids
discharged from the turbine 204 to produce a separated gas to a line 258 and a
separated mixture of liquids and gas to a line 260. The line 258 is connected
for
cariying the separated gas produced by the separator 256 to an inlet (not
shown) of
the compressor 200, and the line 260 is connected for carrying the separated
mixture of liquids and gas produced by the separator 256 to the oil-eniiched
mixture line 80 for transport to the pipeli.ne (not shown).
In the operation of the system shown in Fig. 10, the oil-enriched mixture.
flows through the oil-enriched mixture line 80 to the pipeline (not shown)
which
carries the mixttire to downstream facilities for -further processing.
Separated gas
is canied through the gas line 82 to the heat exchanger 236, which transfers
heat to
the separated gas, and through the line 246 to the turbine 204. The heated
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separated gas drives the turbi.ne 204, which then drives the compressor 200,
and
the gas, -,'vith some condensate liquids, is then discharged from the turbine
through
the line 254 to the separator 256. The separator 256 separates at least a
portion of
the gas from the mixture of gas and liquids discharged from the turbine 204 to
produce a separated gas to the line 258 and a separated mixture of liquids and
gas
to the line 260. The separated mixture of gas and liquids produced by the
separator 256 is carried through the line 260 to the oil-enriched mixture line
80
which transports the mixture with the oil-enriched mixture to the pipeline and
downstream processing equipment (not shown). The separated gas produced by
the separator 256 is canied through the line 258 to and through the compressor
200, and through the line- 234a to and through the second stage compressor
250.
The compressors.200 and.250 are driven by the turbine 204 and the power source
252, respectively, to compress the gas to the injection pressnre, defined
above,
and, as a consequence of the compression, the gas is also beated. The
compressor
250 discharges the compressed and heated gas through the line 234b to the heat
exchanger 236 which transfers heat from the compressed and heated gas to the
separated gas cariied by the gas line 82. The heat transferred through the
heat
exchanger 236 to the separated gas, carried by the gas line 82 and discharged
from
the heat exchanger to the line 246 to drive the turbine 204, should be
sufficient to
maintain a temperature of that gas, as it is discharged from the turbine,
which is
high enough to prevent paraffin's and/or hydrates from forming in the gas. The
compressed gas is then carried from the heat exchanger 236 by the gas return
line
84 to an injection well (not shown) for injection into the injection zone 30
(Figs. 2-
5) as discussed above.
In an alternate embodiunent of the system shown in Fig. 10, the syst.em may
be con.Ggured without the second stage compressor 250 and the accompanying
power source 252,. and the lines 234a and 234b may be coupled to carry
compressed gas from the compressor 200 to the heat exchanger 236, Operation of
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such an alterna.te embodiment would otherwise be substantially similar to the
operation of the embodiment shown in Fig. 10.
The-investment to install the system of the present invention in a plurality
of wells to reduce the gas produced from a field is substantially less than
the cost
of providing additional separation and compression equipment at the surface.
It
also requires no fuel gas to drive the compression equipment since the
pressure or
combustion of the flowing fluids can be used for this purpose. It also permits
the
injection of selected quanlities of gas from individual wells into a downhole
injection zone, such as a gas cap, from which wells oil 'production had become
li.mited by reason of the capacity of the lines or tubing to carry produced
fluids
away from the well, thereby pezxnitting- increased production= from such
wells. It
can also make. certain. formations, which had previously been uneconomical to
produce frorn, economical to produce from because of the ability to inject the
gas
downhole.
Having thus described the present invention by reference to certain of its
preferred embodiments, it is noted that the embodiments disclosed are
illustrative
rather than limiting in nature and that many variations and modifications are
possible within the scope of the present invention.. Many such variations and
modifications may be considered obvious and desirable by those skilled in the
art
based upon a review of the foregoing description of preferred embodiments.
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