Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
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PRETREATMENr OF RAW NATURAL
GAS PRIOR TO LIQUEFACTION
SPECIFICATION
A number of commercial processes are in use for
treating and separating raw wellhead gas. United States
Patent 3,393,527 presents a method of separating heavier
hydrocarbons from a natural gas wherein work is performed
through expanding the gas. United States Patent 3,653,220
presents a process for recoveriny helium in which the raw
gas is dried and treated to remove C02 at high pressure.
; This process differs from the present invention by the partial
decompression and preliminary cooling of the gas prior to
its expansion in a power recovery turbine.
Literature exists as to individual operations for
the treatment of natural gas. For instance, the Engineering
Data Book, 9th Ed., published by the Natural Gas Processers
Suppliers Association, Tulsa, Oklahoma gives a description
and design estimate basis for many types of gas dehydration
techniques including the use of liquids such as glycols,
solid desiccants and expansion refrigeration. This same
reference also has a section on treating natural gas to remove
acid gases by the processes of chemical reaction, physical
solution and adsorption. Many commercial processes used
for drying, sweetening, recovering natural gas liquids, manu-
facturing liquefied natural gas and removing carbon dioxide,
hydrogen sulfide and nitrogen are described in the section
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comprising pages 93-122 of the April 1971 edition of Hydrocarbon
Processin~.
The invention provides a process for pretreating
raw wellhead gas which reduces the liquefaction refrigeration
power requirements by utilizing the energy recovered in expanding s
the raw gas and which reduces the volume of gas which must
be dried in expensive desiccant beds prior to liquefaction.
A broad embodiment of the invention comprises the steps of
sweetening and drying the raw natural gas at a pressure above
55.4 atmospheres, depressuring the gas to a pressure under
14.6 atmospheres in an energy recovery means delivering shaft
horsepower, scrubbing the resultant depressured gas with
a lean hydrocarbon stream to remove hydrocarbons having two
or more carbon atoms per molecule, passing the remaining
lS gas stream through a second drying operation to provide a -~
gas stream suitable for liquefaction, stripping C1-C3 hydrocarbons
from the rich hydrocarbon stream formed by scrubbing the
; depressured gas stream and using a portion of the resultant
liquid as the lean hydrocarbon stream.
The drawing illustrates the preferred ernbodiment
of the invention. A strearn of raw natural gas is removed
from the wellhead 1 and transported through line 2 at a pressure
substantially equal to the wellhead pressure. This stream
is first passed through a sweetening zone 3 wherein acid
` 25 gases such as H2S and C02 are removed. Preferably, this
is performed by countercurrent contacting with a stream of
a lean amine solution entering in line S, and the resultant
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rich amine solution is removed via line 6. The now sweetened
natural gas stream continues through line 4 to a first drying
zone 7 wherein water is transferred to the dry glycol entering
in line 10 to form a wet glycol stream removed in line 9.
. 5 The resultant stream of dried natural gas is then passed
through line 8, which may be a rather lengthy gathering or
transfer line, to an expansion turbine 11. The enthalpy
of the gas stream is reduced through expansion and the delivery
. of shaft horsepower to an energy consuming device such asa compressor 12 in the downstream liquefaction operation.
The depressurized gas is transported into a scrubber
14 through line 13 and contacted with a lean hydrocarbon
stream entering in line 15. Conditions maintained within
: the scrubber effect the transfer of some methane and very
` l5 substantial percentages of heavier hydrocarbons into the
lean hydrocarbon stream to form a rich hydrocarbon stream
removed in line 22. This rich stream is then stripped in
fractionation column 23 to remove methane in line 24. The
remaining hydrocarbons pass via line 25 into column 26, in
which a stream of ethane removed in line 27 is separated.
:~ Finally, the hydrocarbons enter column 29 through line 28,
and a stream of propane is removed via line 30.
This fractionation sequence produces a stream of
: C4 plus liquid removed in line 31. A net liquid product
stream is diverted into line 32 and passed into a splitter
column 33, which produces a stream of relatively pure butane
discharged through line 34. A stream of naphtha like condensate
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is removed via line 20. The remaining portion of the C4
plus liquid is cooled in a heat exchange means 35 and passed
into the scrubber as the lean hydrocarbon stream.
A methane rich gas stream is removed from the scrubber
through line 16 and passed into a second drying zone 17.
This is preferably a solid desiccant type of drying operation.
The resultant dry gas stream is now suitable for passage
into a liquefaction zone 18, from which a liquid stream comprising
methane is removed via line 21.
Many accessories and subsystems have not been shown
for the purposes of clarity and simplicity. This drawing
and description are therefore not intended to limit the scope
of the broad embodiment of the invention to the specific
arrangement illustrated.
Raw natural gas must be treated prior to its liquefaction
~; for several reasons. These include removing compounds which
interfere with or hinder the liquefaction process, the recovery
of hydrocarbon liquids and meeting the product specifications
set for the products. The gas must be dried to prevent ice
formation in the process during cryogenic operations and
hydrogen sulfide cannot be tolerated due to its toxic nature.
The present invention therefore f1nds utility in the pretreatment
of natural gas to be liquefied.
; Raw natural gas is often produced at a wellhead
pressure of from 55.4 to 273.1 atmospheres or higher. Very
high pressure gas is normally throttled to a pressure of
about 103.0 at the wellhead to allow the use of more easily
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fabricated piping, flanges and valves. This gas is then
passed into a sweetening zone operated at conditions effective
to cause the removal of acid gases including hydrogen sulfide
and carbon dioxide. These conditions will include a pressure
near the wellhead pressure or the lower pressure of the throttled
raw gas. This zone may utilize any system which is capable
of removing these gases effectively down to a level of less
than 50 ppm. and which is economical at this high pressure.
C2 is normally present to a greater extent in natural gas
than H2S. It is removed to prevent it from freezing out
in subsequent cryogenic processing.
It is preferred that the sweetening zone comprises
an amine treating operation wherein the raw gas is passed
through a contactor countercurrently to a liquid amine solution.
; l5 The amine is used as an aqueous solution and has no selectivity
for H2S or C02. Ethanolamines are one of the most commonly
used reagents and are well suited for gases rich in heavier
hydrocarbons. Diethanolamine (DEA) is used when the gas
stream contains carbonyl sulfide which reacts irreversibly
with monoethanolamine (MEA). This type of sweetening is
similar to that performed in the Girbotol process.
In MEA units the total acid gas pickup is normally
limited to about 0.33 moles of acid gas/mole of MEA. The
concentration of the MEA is generally held within the 15
to 18 wt.% range to limit corrosion. DEA may be used at
concentrations of up to 25 wt.%. With both solutions the
contactors and the associated amine strippers will typically
have from 18 to 22 trays.
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Other processes are also available for sweetening.
For instance, the Sulfinol process uses a solvent composed
of sulfolane (tetrahydrothiopene dioxide), di-isopropanolamine
(DIPA) and water. Diglycolamine (DGA) at concentrations -
ranging from 50 to 70 wt.% in an aqueous solution can also
be used to sweeten natural gas containing carbonyl sulfide
and/or carbon disulfide. DGA is sometimes preferred since
it can be used in colder climates than the other amines.
Another grouping of processes arethe hot carbonate
type developed by the U.S. Bureau of Mines. They employ
an aqueous solution of potassium carbonate which is circulated
through an absorber and regenerator at a temperature of about
110 to 116C. The process is limited in that it cannot be
used on a gas stream containing only H2S. The most popular
~ l5 hot carbonate processes contain a proprietary activator.
- These are known as the Benfi~ld process, the Catacarb process
and the Giammarco-Vitrocoke process.
Sweetening may also be performed through the use
of a process in which the H25 is reacted with a hydrated
iron oxide and the iron oxide is then intermittently regenerated
or replaced. This method is mainly used with gases having
a low concentration of H2S.
The sweetening zone may contain a separate system
` for the removal of H2S. One system suitable for this is
the Stretford process in which the gas is washed with an
aqueous solution containing sodium carbonate, sodium vanadate,
anthraquinone disulfonic acid and traces of chelated iron.
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Only small amounts of C02 may be removed by this process,
but essentially complete removal of H2S is possible. The
process may be operated over a wide pressure range starting
at a few inches of mercury and is normally run at a temperature
of from ambient to 49C. The hydrogen sulfide dissolves
in the alkaline solution and is oxidized to elemental sulfur
by reaction with the vanadate. The circulating liquid is
regenerated by air blowing, and the sulfur forms a scum removed
by froth flotation.
Physical solvent processes also find application
in sweetening. The more popular processes use such solvents
as anhydrous propylene carbonate, a dimethylether of polyethylene
glycol and methanol. The absorber is a conventional trayed
or pac~ed tower. Regeneration is by one or more of the following
techniques: multi-stage flashing, low temperature stripping
with an inert gas, or heating and stripping with the liquid
vapor.
Sulfur compunds can also be removed through the
; use of adsorption techniques including molecular sieve processes.The now sweetened natural gas, while at a pressure
which is reduced from that at the wellhead only by the inherent
pressure drops within the transfer lines and sweetening zone
and any throttling, is then passed into a first drying zone
which is also operated at this high pressure. Water is removed
at this point to prevent the formation of hydrates in transmission
lines and to meet water dew point requirements. The basic
dehydration techniques include absorption using solid or
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liquid desiccants and dehydration by expansion refigeration.
This may include intentionally freezing out the water. In
general any systern capable of drying the gas down to about
-29C. dew point may be used. However, it is preferred that
the first drying zone effects the formation of a stream of
dried natural gas having a dew point of -40C. (about nine
pounds water per million SCF). A nominal -40C. dew point
gas will have dry pipe1ine walls at 62.2 atmospheres pressure
- and any temperature above 3C. The degree of water removal
necessary in the first drying zone will depend on several
factors including the ambient temperature to which the trans-
mission lines are exposed. Thus, in arctic climates the
nominal dew point (measured at 1 atmosphere) will have to
be much lower than -29C.
It is preferred that the first drying zone consists
of a glycol type drying system. The most commonly used glycols
are triethylene glycol (TEG), diethylene glycol (DEG), and
ethylene glycol (MEG). The basic elements to a glycol drying
system are an inlet gas scrubber, a glycol gas contactor,
a glycol regenerator and a heat-exchanger. The drying process
comprises pumping~regenerated glycol to the top tray of a
contactor (absorber) and removing water-rich glycol from
the bottom of the contactor. This glycol is heat exchanged
with regenerated glycol and passed into the regenerator.
The regenerator may be operated at atmospheric pressure within
a temperature range of about 191 to 204C. This mode of
operation can produce regenerated TEG having a concentration
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of 99.0 wt.%. A stripping gas at rates up to 1045 std. m3/m3
TEG is used in the regenerator if higher glycol concentrations
are desired. Glycol circulation rates may vary from about
.017 to .042 m3 of glycol per Kg. of water to be removed.
The countercurrent contacting may be carried out over a range
of temperatures, with operation at the minimum available cooling
water temperatures below 49C. being preferred. The recirculation
rate and the number of trays used in the contactor will vary
depending on such factors as the desired dew point depression.
Typical contactors have from four to eight or more trays.
Solid-desiccant dehydration operations normally
use a material which is regenerated in two or more beds used
on a swing basis. It is possible to reduce the water content
of the gas to less than 1 ppm. with a solid desiccant. As
l6 a result they are commonly used to dry gas prior to cryogenic
processing and are preferred for use in the second drying
zone of the subject invention. The specific desiccant to
be used depends on the composition of the gas stream and
the dew point required. Some desiccants are adversely affected
by acid gases, well treating chemicals and heavier hydrocarbons.
Activated alumina, silica gel and silica-alumina beads are
some of the more common suitable materials. Molecular sieves,
such as a type 4A sieve, are another group of suitable materials.
Further details on the use of desiccants can be obtained
from standard references including for instance, United States
Patent 3,205,683.
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Dehydration can also be performed through expansion
refrigeration. This method is not preferred since it lowers
the pressure of the gas stream. However, it may be utilized
when the available field pressure is extremely high. Often
a hydrate inhibitor is injected either continuously or intermittently.
Ethylene glycol is the most commonly used, with other inhibitors
being diethylene glycol and methanol. The glycol and its
absorbed water are separated from the gas stream along with
liquid hydrocarbons. United States Patent 3,537,270 illustrates
a natural gas dehydration process using expansion and is
representative of the level of the art.
The terrns "sweetening zone" and "drying zone" are
intended to refer to all functional means for performing
these operations. It is consistent with this that the zones
may be combined. Therefore the removal of both acid gases
and water in a single integrated system is intended as within
the scope of the invention. Some solvent and molecular sieve
operations are capable of rernoving both H2S and water from
- the gas. For instance, United States Patent 3,~37,143 describes
the use of a dialkyl ether of a polyalkylene glycol ether
containing 2 to 15 wt.~ water as solvent, and United States
Patent 3,841,058 presents an improvement in the removal of
water and carbon dioxide by solid absorbents and the regeneration
of the absorbents. There may also be included within or
in conjunction with the sweetening and drying zones a means
for removing nitrogen and thereby increasing the heating
value of the gas. United States Patent 3,791,157 illustrates
one such nitrogen removal process.
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Following the remova1 of acid gases and water,
the remaining portion of the natural gas stream is passed
into an energy recovery means in which the gas stream is
depressured. The energy recovery means may be located a
substantial distance away from the first drying zone. This
is because economics generally favor transportation of gases
at an elevated pressure. The energy recovery means may be
of any type which will deliver shaft horsepower and effect
a reduction in the enthalpy of the gas strearn. Energy can
be effectively recovered down to a pressure of about 7.8
to 20.4 atmospheres. Consideration must of course be given
to the pressure desired for the subsequent scrubbing and
liquefaction operations. It is preferred that the energy
recovery means drive equipment used in the liquefaction zone.
It is also preferred that the energy recovery means is a
turboexpander. These devices are already in widespread use
,- and their design is well known to those skilled in the art.; More specific information is available from standard references
including the article on pages 227-234 of February 1973 edition
of the Journal of Engineering for Indu try.
The resultant low pressure stream of dried and
sweetened natural gas is then passed into a scrubbing zone
in which it is countercurrently contacted with a lean liquid
hydrocarbon stream. The purpose of this operation is to
remove heavier hydrocarbons, a term which is intended to
refer to all hydrocarbons having more than two carbon atoms
per molecule. The scrubbing zone should remove over 50%
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of the ethane and substantial1y all of the propane, butanes,
pentanes, etc. As used in this context the term substantially
all is intended to refer to the removal of over 90 mol.%
of each hydrocarbon. This results in the formation of a
net gas stream rich in methane, but also containing nitrogen
ancl ethane. This net gas stream is the charge stock for
the liquefaction zone and should contain at least 80% Methane.
The volume of the net gas stream will normally be about ~0
to 85% of the raw natural gas. This is advantageous as it
allows a reduction in the required size of the downstream
second drying zone.
The design and operation of scrubbing zones is
well known. It is preferred that a vertical column containing
;- five or more trays is utilized, but a packecl tower may be
substituted. Higher pressures favor the transFer of the
heavier hydrocarbons into scrubbing liquid, and it is therefore
preferred that the scrubbing zone is operated at a pressure
above 4.4 almospheres. A temperature of from about 16C. to
93C. should be maintained in the zone. As the scrubbing
operation is exothermic, this may require the subcooling
of one of the feed streams or the provision of intermediate
cooling means. It is preferred that ~4 to C6 hydrocarbons
predominate in the scrubbing liquid and that hydrocarbons
having more than 6 carbon atoms per molecule comprise less
than 30% of the circulating mixture. A circulation rate
of about 1 to 3 moles of liquid per mole of incoming gas
is normally utilized.
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The scrubbing liquid is removed from the scrubbing
zone as a resultant rich liquid hydrocarbon stream and passed
into a fractionation zone. This zone may take one of several
forms depending on the desired products. It is preferred
that the fractionation zone comprises three columns, each
of which produces a relatively pure stream of methane, ethane
and propane respectively. The methane stream from this zone
may be admixed with the net gas stream of the scrubbing zone.
Alternatively, all three of these gases may be removed as
a single stream, and this stream if desired can be further
fractionated. The conditions used within the zone will of
course vary with its conFiguration and may be determined
by those skilled in the art. For instance, a rather complex
method of fractionating natural gas components to remove
! l5 heavy hydrocarbons is illustrated in United States Patent
3,393,527.
In the subject process a portion of the resultant
C4 plus lean liquid equal to the amount of its component
materials picked up in the scrubbing zone is divided off.
This amount is preferably split in another fractionating
column to yield a stream of butanes and a stream of liquefied
condensate. The remaining portion of the fractionation zone
effluent is then cooled and passed into the scrubbing zone
as a lean liquid hydrocarbon stream used as the scrubbing
liquid.
The methane-rich net gas stream formed in the scrubbing
zone is passed into a second drying zone. The nature of
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this zone may varyS but it must be capable of drying the
gas down to a dew point of roughly -151C. or below. Preferably,
the dry gas strearn produced in the second drying zone will
have a dew point of -162C. A solid desiccant system such
as previously described is therefore preferred, and especially
preferred for use are alumina and molecular sieves.
In accordance with the preceding description, the
preferred embodiment of my invention may be characterized
as a process for the treatment of raw natural gas prior to
liquefaction which comprises: passing a stream of raw natural
gas having a pressure above 55.4 atmospheres through a sweetening
zone operated at conditions effective to remove carbon dioxide
and hydrogen sulfide therefrom and to thereby effect the
formation of a stream of sweetened natural gas; passing the
stream of sweetened natural gas through a first drying zone
operated at conditions effective to remove water therefromand to effect the formation of a stream of dried natural
gas having a dew point below -29C.~ depressurizing the stream
of dried natural gas in an energy recovery means developing
shaft horsepower to a pressure under 21.4 atmospheres; contacting
the stream of dried natural gas with a lean liquid hydrocarbon
stream in a scrubbing zone operated at conditions effective
to cause the transFer of substantially all hydrocarbons having .
more than two carbon atoms per rnolecule into the lean liquid
. 25 hydrocarbon stream and to effect thereby the formation of
a methane-rich gas stream and a rich liquid hydrocarbon stream;
.~ passing the methane-rich gas stream into a second drying
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zone operated at sonditions effective to remove water from
the methane-rich gas stream and to effect the formation of
a dry gas stream having a dew point below about -151C. and
suitable for passage into a liquefaction zone; passing the
rich liquid hydrocarbon stream into a fractionation zone
operated at conditions effective to remove hydrocarbons having
from one to three carbon atoms per molecule from the rich
liquid hydrocarbon stream and to effect thereby the formation
of a C4 plus liquid hydrocarbon stream; and dividing the
C4 plus liquid hydrocarbon stream into two portions and passing
one of the portions into the scrubbing zone as the lean liquid
hydrocarbon stream.
The dry gas stream produced in the second drying
zone will normally be,suit,able for insertion directly into
a liquefaction zone. Presently three basic cycles for the
liquefaction of natural gas are known to those skilled in
the art. These are generally referred to as the Cascade
Cycle, the Multi-Component ~efrigerant Cycle and the Expander
Cycle. Each is described in some detail in United States
Patent 3,724,226. These processes are each subject to much
variation. Further examples and details of liquefaction
methods may be obtained by referring to United States Patents,
3,254,495; 3,315,477 and 3,763,658.
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