Note: Descriptions are shown in the official language in which they were submitted.
1 ~0713~
PROCESS FOR TREATING NATURA1 GAS
BACKGROUND OF THE INVENTION
This invention relates to the removal of aci-
dic constituents such as carbon dioxide, hydrogen
sulfide, and other sulfur compounds from naturai gas.
"Sweeteningn, as it is termed, is normally accomplished
by an absorption process, with or withoutichemical
reaction, using solutions of chemical or physical reac-
tants, or combinations of b~th types; of reactants.
Most known processes are regenerative in nature and are~
based on the absorption-stripping~ ~ principle.
More specifically, natural gas treatment or
"sweetening" îs generally accomplished by contacting
the sour natural gas stream which may contain varying
quantities of carbon dioxide, hydrogen sulfide and
other sulfur compounds, with any one of a variety of
known physical or chemical solvent reagents, or a com-
bination of both, in an absorber. The solvent reacts
chemically and/or absorbs acid fractions in the sour
natural gas producing a marketable natural gas stream.
The solvent is generally regenerated by ~lashing the
acid gas therefrom by pressure reduction and~or heating
the solvent to its boiling point in a stripper column.
Solvent recovered from the regeneration system is
cooled and recirculated back to the absorber column.
It is to be noted that absorption of acid
molecules by either physical reactants or chemical
solvents is exothermic in nature and, accordingly, the
system temperature rises. As the system temperature
.s`,'~
i2~7~3~L
increases the reaction rate slows, approaching an
equilibrium condition. At a given temperature for each
system the reaction stops and regeneration starts.
Moreover, when the sweetening reaction slowsl unreacted
acid compounds may contaminate the system.
Another recognized problem is that the
denuding of acid gas from the solvent in the solvent
regeneration stripper is seldom complete and the resi-
dual acid components sometimes tie up as much'as 20% of
the reactive solvent,~ seriously reducing its effec~
tiveness andfor requiring higher solvent circulation
rates to accomplish the desired result. Thus, energy
consumption for operating a gas sweetening ùnit is
generally proportional to the solvent circulation rate.
In natural gas systems containing both carbon
dioxide and hydrogen sulfide it is generally important
that the amount of unreacted hydrogen sulfide be
limited to a maximum Qf 4 ppm (parts per million) in
the treated stream while the allowable carbon dioxide
content may commonly reach 2,000 to 30,000 ppm in the
system. Therefore, in order to denude the solvent to a
point where essentially all of the hydrogen sulfide
will be absorbed, excessive amounts of carbon dioxide
must be first reacted and then regenerated to insure
that essentially all of the hydrogen sulfide will be
removed from the treated stream.
In most exothPrmic reactions an increase in
temperature is detrimental to the reaction. Elevations
in temperature of up to 30 to 40F are common in the
absorber particularly in systems containing significant
~ZC~7~L3~
quantities of sour components. Such temperature
increases in the sour system increase the corrosion
rate. Also, the amount of energy required to rege-
nerate the reagent rises significantly as the degree of
regeneration increases. To overcome the potential
negative Pffect of the higher system temperature
excessive quantities of reagent are commonly cir-
culated.
SUMMARY OF THE INVENTION
In order to minimize equipment costs, pumping
costs, regeneration energy consumption, and ~iinhib;t
corrosion products, the process of the instant inven-
tion utilizes a modified flow path as compared to
natural gas sweetening procosses currently known. By
introducing regenerated solvent to the partially
sweetened natural gas stream at a point upstream of the
absorber, an immediate exothermic reaction or secondary
absorption begins between any unabsorbed acid molecules
and the solvent. The two streams are mixed, comingled
and ed to a cooler to remove latent heat, sensible
heat, heat of reaction and heat of absorption.
Accordingly, the end contact temperature between the
natural gas and solvent is relatively low. The cooling
medium may be air, water, rerigerant or other fluids.
After any unabsorbed acid components of the
natural gas and the solvent have reacted and are
cooled, the mixture flows from the cooler to a separa-
tor where thP sweetened gas is separated from the par-
tially fouled solYentO The sweetened natural gas is
lZ07~3~
then distributed to an end use and the solvent pumped
back to ~he absorber for initial absorption of acid
constituents from the raw or sour natural gas feed
stock.
Since the temperature in the absorber is
substantially reduced for any given specific quantity
and quality of solvent and natural gas acid components,
by the process of the instant invention, less solvent
is required to accomplish the same degree of treatment
compared to known treatment systems.
Computer model simulations of the instant
invention indicate that the solvent circulation rate
can be substantially reduced and regeneration heat
energy reduced by 20~ where the amount of carbon
dioxide in the natural gas stream is the controlling
factor. In the same system where the removal of hydro-
gen sulfide is the controlling factor, the regeneration
heat requirement is reduced to 50% of conventional
systems.
BRIEF DESCRIPTION OF THE DRAWINGS
Figure 1 is a schematic flow diagram of the
natural gas treatment system of the instant invention,
wherein the carbon dioxide percentage limit in the
~reated natural gas is the controlling factor,
Figure 2 is a view, similar to Fig. 1, wherein
the hydrogen sulfide percentage limit is the
controlling factor.
`` ~LZ~7~3:L
DETAILED DESCRIPTION OF TH~ PREFERRED
EMBODIMENT OF THE INVEN~ION
As best seen in Figure 2 of the drawings, a
process for removing acidic contaminants such as carbon
dioxide, hydrogen sulfide, and other sulfur compounds
from raw or sour natural gas termed "sweetening"
comprises the steps of introducing sour natural gas
feed stock to an inlet separator 10. Thereafter, ca~-
bon dioxide and hydrogen sulfide are removed from the
sour gas stream by initially contacting the stream, at
a temperature of 115F and pressure of 915 PSrA, with a
~nown chemical or physical solvent, or a mixture of
chemical and physical solvents, in a multistage coun-
tercurrent absorber 12. The initially treated natural
gas stream leaves the top of the absorber 12 through a
conduit 14 at a temperature of 135F and the fouled
solvent leaves the bottom of the absorber 12 through a
conduit 16 at a temperature of 156F.
The fouled liquid solvent is then introduced
at a relatively low pressure of 85 PSIA to a flash tank
18, the flashed vapor being removed from the system.
The resultant degassed but fouled solvent is conducted
from the flash tank 18 at a temperature of 155F to a
heat exchanger 20 wherein its temperature is elevated
from 155F to 220F.
The fouled solvent is conducted from the heat
exchanger 20 to a solvent regenerating stripper column
22 wherein carbon dioxide and hydrogen sulfide are
removed. A carbon dioxide and hydrogen sulfide rich
gas stream is conducted from the stripper column 22 at
~ 2~ /1 3 ~
a temperature of 182F to a condenser 24, wherein the
stream temperature is reduced to 120F, thence to a
separator 26. The resultant acid gas at 120F is then
incinerated, directed to a sulfur producing plant, or
used as feed stock to other chemical units. Condensate
from the separator 26, at 20 PSIA, is conducted to a
pump 28 thence to the top of the stripper column 22.
Stripped solvent at 254F is withdrawn from
.. . .
the bottom of the stripper 22 and is pressurized by a
pump 30 to 27 PSIA for delivery to the heat exchanger
20, thence to a solvent cooler 32 at a temperature of
184F
In accordance with one feature of the instant
invention, cooled solvent from the cooler 3~ at 120F
is pressurized by a pump 34 for introduction into the
conduit 14 containing the initially treated natural gas
stream emanating from the top of the absorber 12. Any
residual acidic constituents in the initially treated
natural gas stream are absorbed, further "sweetening"
the resultant gas stream.
The mixed natural gas stream and partially
fouled solvent stream, at a temperature of 135F, are
passed through a cooler 36 further lowering the tem-
perature to 114.6F at a pressure of 910 PSIA facili-
tating further lowering of the carbon dioxide and
hydrogen sulfide content in the resultant treated
natural gas leaving the system.
The fully "sweetened" natural gas is dis-
charged from the outlet separator 38, while the par-
tially Pouled solvent is conducted to the top of the
z~
absorber 12 for initial treatment of the acid molecules
in the natural gas stream.
As seen in Fig. 2, the sweetening system is
tuned to operate in a mode wherein the percentage limit
of hydrogen sulfide is the controlling factor.
Use of the aforesaid two-stage sweetening pro-
cess maximizes efficiency of the system in removing
contaminants from the natural gas stream. Carbon
dioxide, hydrogen sulfide and other sulfur compounds
left in the stripped solvent leaving the solvent rege~
nerating column 22 can be increased and/or the solvent
circulation rate can be decreased while maintaining the
same amount or 125s of carbon dioxide contaminant
and/or lowering the amount of hydrogen sulfide in the
treated natural gas stream. ~ny increase of con-
-taminants in the solvent does not require a propor-
tional increase in reflux of the solvent in the
regenerating stripper thereby lowering the amount of
energy required to strip the solvent. The lower reflux
and stripper requir~ment reduces capital expenditures
for equipment and materials.
A high degree of selectivity is achieved in
removing hydrogen sulfide from the natural gas feed
stock while permitting relatively high amounts of car-
bon dioxide in the treated natural gas. Moreover,
while the solvent circulation rate may be reduced, a
reduction in the reflux energy requirement and the
energy required for solvent pumping and stripping is
evidenced. A reduction in the size of eguipment and
materials heretofore used is al50 possible while main-
-
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taining the same or lower amounts of hydrogen sulfide
in the treated natural gas. Selective removal of the
amount of hydrogen sulfide from the sour feed stream
requires less energy for incineration of the acid gas
stream exiting the solvent regenera~ion stripper 22 and
separator 26. The general reduction in system tem-
peratures permits higher loadings of acid molecules in
the solvent and permits higher concentrations of
stripped solvents without increasing corrosion effects
thereby reducing required water makeup. Power consump
tion of the sol~ent circulating pumps is also reduced.
The following Tables I, II and III reflect,
respectively, the operating parameters of, a prior art
system, a system of the instant invention wherein the
carbon dioxide percentage limit in the treated gas is
controlling, and a system of the instant invention
where the hydrogen sulfide percentage limit in the
treated gas is controlling~
07131
TABLE I - PRIOR ART
STREAM FLOW RATE SUMMARY - LB - MOLES/HR
HYDROGEN CARBON
STREAM MDEA NITROGEN SULFIDE DIOXIDE WATER METHANE ETHANE
A --494.07 0.66548.8212.825547.57 5.28
B 867.220.25 0.82455O615695.995.28 0.01
C 862.220.01 0.81449~075~95.330.23 --
D 862.22 -- 0.175.285703.52 -- --
E __493.82 0.0198.52200355542.29 5.27
F -- 0.24 0.016.540~66 5~04 0.01
G -- 0.01 0.64443.7641.860.23 --
Solvent Circulation: 400 Gallons~Minute
Heating Required: Stripper Reboiler Duty = 24.03 ~BTU/Hr,
TABLE I~ - (SYSTEM OF FIG~ 1)
STREAM FLOW RATE SUMMARY - LB - MOLES/HR
HYDROGEN CARBON
STREA~ MDEA NITROGEN SULFID~ DIOXIDE WATER METHANE ETHANE
A ~-494.07 0.66548.8212.825547.57 5.28
B 836.050.26 0.89458.785534.775.27 0.01
C 836.05OoOl 0~88454.72553~.380.30 --
D 836.05 -- 0.236.735530.35
E --493.81 0.0196.768.405542.59 5.27
F -- 0025 0.014.060.39 4.97 0.01
G -- 0.01 0~65448.0042.260.30 --
Solvent Circulation: 388 Gallons/Minute
Heating Required: Stripper Reboiler Duty = 20.04 MMBTU/Hr.
207~3~L
TABLE III -- lSYSTEM OF FIG. 2~
STREAM FLOW RATE SUMMARY -- LB -- MOLES/HR
HYDROGEN CARBO~
STREAM MDEA NITROGEN SULFIDE DIOXIDE WATER MET~ANE ET~ANE
A --494.07 n . 66548.82 12.~2 5547.57 5.28
B 474.150.15 0.83283.423140.743.11 --
C 474.150.01 0 83281.493140.580.19 --
D 474.15 -- 0.183.243136.44 -- --
E --493.92 0.01268.658.525544.46 5.28
F __0.14 0.Q11.940.15 2.92 ~-
G -- 0.01 0.64278.2326~270.19 --
Solvent Circulation: 220 Gallons/Minute
Heating Required: Stripper Reboiler Duty = 12.43 MMBTU/Hr.
~ hile the preferred embodiment of the invention has been
disclosed, it should be appreciated that the invention is suscep-
tible of modification without departing from the scope of the
following claims.
