It is revealed that modifying the solution of this process using sodium hydroxide increases the capacity of the solution in removing acid gases.. Based on the presented results, when the
Trang 1Synergy between two natural gas sweetening processes
Abolghasem Kazemia,⇑, Abolfazl Gharibi Kharajib, Arjomand Mehrabani-Zeinabada, Vafa Faizib,
Jalalaldin Kazemic, Ahmad Shariatid
a
Chemical Engineering Department, Isfahan University of Technology, Isfahan, Iran
b
Chemical Engineering Department, University of Isfahan, Isfahan, Iran
d
Natural Gas Engineering Department, Petroleum University of Technology, Ahwaz, Iran
a r t i c l e i n f o
Article history:
Received 11 September 2014
Revised 27 November 2015
Accepted 5 January 2016
Available online 6 February 2016
Keywords:
Carbonate based processes
Natural gas sweetening
Merox process
H2S removal
a b s t r a c t
Merox process is a developed process for natural gas sweetening However this process has one main disadvantage, which is the fact that carbon dioxide in the feed gas consumes the sorbent solution High efficiency of carbonate based solutions for removal of bulk of CO2from natural gas is a well-known fact The alkalinity is important in removal of acid gases by potassium carbonate solution The main idea behind this work was to investigate the possibility of inhibition of Merox solution consumption
by a synergy between Merox and carbonate based sweetening processes In this study, a carbonate based sweetening process is simulated using Aspen Plus simulator for sweetening the natural gas produced in one of gas fields located in Iran The effects of addition of sodium hydroxide to the solution on the gas sweetening performance and efficiency are investigated It is revealed that modifying the solution of this process using sodium hydroxide increases the capacity of the solution in removing acid gases
Ó 2016 Elsevier Ltd All rights reserved
Introduction
Presence of acid gases in natural gas results in corrosion in
facil-ities and reduction of the natural gas heating value Removal of the
acid gases from natural gas before transmission through pipeline is
inevitable (Iliuta et al., 2004; Amoore and Hautala, 1983; Kohl,
1997; Processors, 2004) The maximum allowable concentrations
of hydrogen sulfide and carbon dioxide for natural gas
transmis-sion are 4 ppm and 2 mol%, respectively (Kidnay and Parrish,
2006; Kohl, 1997) Gas sweetening processes of industrial gas
treating plants must provide (a) complete removal of H2S, (b)
han-dling large flow rates of gas, (c) high pressure operation, and (d)
solution regeneration (Katz and Donald La Verne, 1959; Kohl,
1997; Processors, 2004) For the removal of these two gases from
natural gas, several processes such as amine based, Sulfinol, and
carbonate based processes have been developed (Cousins et al.,
2011; Ghanbarabadi and Khoshandam, 2015; Kazemi et al., 2014;
Kim et al., 2013; Polasek and Bullin, 1984) The possibility of a
syn-ergy between different solutions used for the purpose of natural
gas sweetening is arisen by usage of different Sulfinol solutions
and mixed amine solutions In various Sulfinol processes a mixture
of either diisopropanol amine–sulfolane or MDEA–sulfolane and in
the mixed amine processes a mixture of tertiary amines and sec-ondary (or primary) amines are used for natural gas sweetening (Anufrikov et al., 2007; Erga et al., 1995; Fouad and Berrouk, 2013; Idem et al., 2005; Kazemi et al., 2014; Kohl, 1997; Nuchitprasittichai and Cremaschi, 2011; Processors, 2004; Rajani,
2004) In Sulfinol-M, Sulfinol-X and Sulfinol-D processes a synergy between chemical and physical absorption of acid gases, while, in mixed amine processes synergy between methods of chemical absorption are exploited Each of the mentioned processes combi-nes advantages of the two solutions while the advantage of each solution covers for the disadvantage of the other one
Solution of 20 wt% potassium carbonate can be used for natural gas sweetening This solution has a large capacity for chemical absorption of CO2and also in presence of SO2it is a cost effective process (Wappel et al., 2009) A large number of the natural gas sweetening plants around the world (over 700 sweetening plants) implement the potassium carbonate process (Rufford et al., 2012) Sodium hydroxide (NaOH) can react with the acid gases H2S and
CO2 according to the reaction set (1), which are occurring in namely Merox natural gas sweetening process (Jensen et al., 1966; Kohl, 1997)
NaOHþ H2S$ NaHS þ H2O 2NaOHþ H2S$ Na2Sþ 2H2O 2NaOHþ CO2$ Na2CO3þ H2O
ð1Þ
http://dx.doi.org/10.1016/j.juogr.2016.01.002
2213-3976/Ó 2016 Elsevier Ltd All rights reserved.
Contents lists available atScienceDirect
Journal of Unconventional Oil and Gas Resources
j o u r n a l h o m e p a g e : w w w e l s e v i e r c o m / l o c a t e / j u o g r
Trang 2Merox process is used for the removal of small quantities of CO2
and H2S from natural gas and refinery gases (Kohl, 1997; Raab,
1976; Manieh and Ghorayeb, 1981) One of the main problems of
this process is consumption of the solution upon contact of carbon
dioxide On the other hand, high efficiency of potassium carbonate
process in removal of CO2according to reaction(2)is an important
and well-known fact:
K2CO3þ CO2þ H2O$ 2KHCO3 ð2Þ
Considering these facts, this study investigate a possible
syn-ergy in acid gas removal with the use of a combination of these
two solutions, each of which taking a part in chemical absorption
of each of the main two acid gases
The sour gas composition
The composition of the sour gas entering the unit, is supposed
to be the same as feed gas of a sweetening unit at northern east
of Iran The composition of sour natural gas of this gas field is
according toTable 1
Steady state, rate based simulation
Simulation
The gas sweetening unit that is located in Iran was simulated by
Aspen Plus process simulator Because of the ionic nature of the
reactions, the property model for the simulation must utilize a true
component approach in order to model short range forces between
molecule–molecule, ion–molecule and ion–ion and also long range
forces between ion–ion species Thus, ELECNRTL model is used for
simulation of this process (ASPEN, 2012; Chen et al., 1979)
In previous studies, the rate-based distillation model in Aspen
Plus was used for the modeling of the absorber in natural gas
sweetening plants (Zhang et al., 2009; Tönnies et al., 2011;
Jayarathna et al., 2011; Qi et al., 2013) Equilibrium distillation
model is not suggested for the modeling of the chemical absorption
processes (e.g carbonate based processes) because of its inability
in prediction of the effect of reactions on the heat and mass
trans-fer phenomena (Mudhasakul et al., 2013) The rate-based model
solves mass and heat transfer correlations along with liquid holdup
correlations (Mudhasakul et al., 2013; Zhang et al., 2009)
Never-theless, for the modeling of stripper column, as suggested by
Mudhasakul et al., due to higher temperatures and higher reaction
rates, equilibrium approach will result in the same results as the
rate-based approach (Mudhasakul et al., 2013) Thus, rate-based
and equilibrium approaches were used in modeling the absorber
and stripper columns, respectively
In accordance toTable 1, there is 0.2 mol% of C7+ in the feed gas
As this hydrocarbon cut contains hydrocarbon molecules with 7 or more carbons, in the simulation environment normal octane was used instead
Process description The simulation was performed based on a flow sheet as pre-sented in Fig 1, however an industrial unit might have different unit operations based on the sour gas conditions and the specifica-tions required for the sweet gas (Chowdhury, 2013) According to
Fig 1, the sour gas at 40°C and 22 atm enters the bottom of absor-ber unit The carbonate solution at 116°C and 26 atm enters the absorber at the top stage In the absorber based on reaction (2)
CO2and H2S of the natural gas are absorbed by the solution The sweet gas leaves the absorber with low H2S and CO2mole fractions The rich solution containing absorbed the acid gases and a little amount of other components present in the natural gas leaves the contactor at the bottom stage The rich solution is transferred
to a solution regenerator, but prior to regenerator it passes through
an expansion valve and then a two phase separator The valve reduces the pressure and temperature of the solution to 2 atm and 101°C The two phase separator operates under these opera-tional conditions In this separator some part of the solution might vaporize and leave the system In the solution regenerator, the absorbed acid gases in the solution leave the system from the top of the column The regenerated solution from the bottom of the column are transferred back to the contactor by passing through a centrifugal pump for rising the pressure to 26 atm and
a heater for setting its temperature to 116°C A makeup solution
is added to the recycle solution in order to adjust the solution loss
in the operational units
Results and discussion The synergy
A set of simulation was designed by application of a change in composition of the solution and the process efficiency was calcu-lated If the applied changes do not affect the H2S and CO2removal efficiencies, then the proposed synergy fails But upon variation of removal efficiencies of the acid gases, a comprehensive interpreta-tion of the results is needed to evaluate the synergy Having this procedure in mind, 10 MMSCFD of the introduced natural gas in
Table 1was processed with lean solution modified with sodium hydroxide at various concentrations The process removal efficien-cies are reported inTable 2andFig 2
As indicated in Table 2 and Figs 2 and 3, upon addition of sodium hydroxide to the lean solution, the H2S and CO2mole frac-tions in the sweet gas decreased The fraction of H2S in the sweet gas reduced to a minimum (less than 1 ppm) at sodium hydroxide weight percent of 5.5%, the mole fraction of CO2in the sweet gas reached a minimum (less than 0.1%) for sodium hydroxide concen-tration of 12 wt% Based on the presented results, when the weight percent of sodium hydroxide in the lean solution is between 0% and 5.5%, the fraction of H2S and CO2 in the sweet gas are decreased But by increasing concentration of the added sodium hydroxide to a value in the range of 5.5–12 wt%, the fraction of
CO2in the sweet gas decreases further, while the fraction of H2S
in the sweet gas does not change Upon increasing concentration
of sodium hydroxide concentration in the solution to a value higher than 12%, the CO2and H2S are almost completely removed from the natural gas
Another important aspect of applying this change is the fact that sodium hydroxide increases the pH of the solution and at a
Table 1
The sour gas composition.
Trang 3higher pH, higher rates of corrosion in facilities are expected (Fang
et al., 2003; Song, 2009) Thus, it should be noted that operating at
a lower level of added sodium hydroxide solution can be more
desirable due to lower tendency of the solution to corrode the
facilities
By application of this change on the carbonate based solutions,
as the alkalinity of the carbonate based solution is increased due to
presence of NaOH in the solution, in order to prevent corrosion
caused by high sodium hydroxide concentration, it is required to
use special arrangements and resistant materials in construction
of the absorber and the piping system or usage of inhibitors It is
recommended to construct absorber and piping system from
mate-rials like stainless steel grade 304 (UNS S30400) or stainless steel
grade 316 (UNS S31600) or polysulfone which are resistant to cor-rosion in high alkalinity Although exploiting this change in current operating carbonate based processes results in corrosion of the facilities due to increase of the solution pH, it is recommended in designing new carbonate based plants By availability of the intro-duced grade of stainless steel for construction, application of this change can expand the operability of the process
Effects of solution modification
As indicated inTable 1, mole fractions of H2S and CO2 in the sour gas were 0.057 and 0.056, respectively In the case of 40MSSCFD of sour gas, after the removal of these two components,
in the sweet gas, at a specific solution circulation rate, the mole fractions of H2S and CO2became 52 ppm and 0.0362, respectively According to these data the removal efficiency of H2S and CO2are 99.9% and 35.5%, respectively
At this point, two scenarios can be defined for meticulously ana-lyzing the simulation results
Scenario 1: modification of the solution to reach pipeline specs for sweet gas
In this scenario, the solution is modified for purifying the feed gas to meet pipeline specifications for the sweet gas It is clear from
Fig 2andTable 2that upon increasing the concentration of sodium hydroxide in solution to 5.5%, the pipeline specifications for the
H2S and CO2are achievable
After application of the proposed change, the outlet H2S and CO2
mole fractions in the sweet gas became 0.5 ppm and 0.009, respec-tively Removal efficiencies were extended to 99.9% and 83.9% for
Fig 1 Simulation flow sheet.
Table 2
Effects of applying the proposed change on the H2S fraction of the processed gas.
processed gas
0 0.005 0.01 0.015 0.02 0.025 0.03 0.035 0.04 0.045
wt% of the modifier added
increased soluon GPM Constant soluon GPM
Trang 4H2S and CO2, respectively Thus, applying the proposed
modifica-tion on the carbonate based solumodifica-tion, for flow rate of 40MMSCFD
of sour gas, results in the removal efficiency of CO2to be increased
by approximately 50% The simulation also was carried out for 4
other flow rates of sour gas, For 20, 30, 50 and 60 MMSCFD the
results are presented inFigs 4 and 5.Fig 5shows that applying
the proposed modification on the carbonate based solution
enhances the removal efficiency of CO2 at an extent of about
50% At different sour gas flow rates, the solution flow rate was
adjusted to reach the defined specifications Thus, the sodium
hydroxide flow rate was altered by changing the flow rate of the
sour natural gas
The enhancement on removal of the sour gas as shown inFigs 4
and 5is due to the competition between the two sorbent solutions
for the chemical absorption of acid gases The Merox solution in
case of high CO2 concentration results in irreversible reactions
which concluded to the issue that the rich solution is not able to
be regenerated and a portion of it must be replaced But in case
of carbonate based solutions this situation is completely different
Thus, the extent of absorption of each of the solutions is a
param-eter which can take a part in the decisions concerning the
applica-tion of this change
Scenario 2: 99.9% removal of CO2and H2S
Another scenario is defined to reach 99.9% removal of both CO2
and H2S in the sweetening process Some of applications of natural
gas require the sweet natural gas with extremely low CO2 concen-trations (Ebenezer and Gudmunsson, 2005; Processors, 2004) This scenario was defined to meet the required specifications for these applications of natural gas Based on the results of this study, as shown inFig 3, upon addition of 12% of sodium hydroxide to the solution, 99.9% of CO2and H2S removal are achievable and the con-centration of CO2falls lower than 0.1% Enhancement in removal efficiency of CO2and H2S are shown inFig 6
0 0.2 0.4 0.6 0.8 1 1.2
wt% of the modifier added
H2S removal efficiency - Increased soluon GPM H2S removal efficiency - Constant soluon GPM CO2 removal efficiency- Increased soluon GPM CO2 removal efficiency - Constant soluon GPM
Fig 3 Effect of application of the proposed change on the acid gas removal efficiencies.
0 20 40 60 80 100
Sour gas flow rate (MMSCFD)
H2S (aer soluon modificaon) increase in CO2( aer soluon modificaon)
CO2 ( without soluon modificaon)
0 10 20 30 40 50 60
Sour gas flow rate (MMSCFD)
increase in H2S increase in CO2
Fig 5 Increase in acid gas removal efficiency for scenario 1 at different sour gas flow rates.
Trang 5Effects of changing the solution (to meet pipeline specifications)
Before modification of the solution for the removal of H2S and
CO2from the specified natural gas (Table 1), to meet pipeline
spec-ifications, 683.4 gallons per minute of the sorbent solution is
needed, based on the simulation results After improving the
solu-tion, 460.4 gallons per minute of the solution are required for
reducing H2S and CO2content of the natural gas to the permission
level according to pipeline specifications The simulation results for
the sweet gas are shown inTable 3
As indicated inTable 3, in order to reach a specific
concentra-tion of H2S and CO2 in the sweet gas, lower circulation rate of
the solution is required after changing the solution This means
that, the sizes of the required potassium carbonate plant
equip-ment would be smaller which results in reduction of the plants
total capital and operating costs (Kazemi et al., 2014) Also the
pos-sibility of extended applicability of Merox process due to chemical
absorption of carbon dioxide in the solution could be a further
advantage One important parameter which could be decisive in
application of the proposed synergy is the capability of successive
regeneration of the solution and in the simulation environment the
regeneration of the changed potassium carbonate solution was not
found to make a problem as it can be recovered for a long period of
time However, further experimental investigations are
recom-mended prior to application of this modification in natural gas
sweetening units
Fig 7shows that in order to reach pipeline specifications for the
sweet gas, at a specific flow rate of the sour gas, the required
circu-lation rate of the modified solution is decreased
According toFigs 6 and 7, the simulators data signify that, at relatively low gas flow rates, changing the solution, increases the removal efficiencies of H2S and CO2, and with a lower solution cir-culation rate, the pipeline specifications for the sweet gas could be obtained This can cause the capital and operating costs along with equipment sizing to decrease (Chapel et al., 1999; Kazemi et al., 2014; Kohl, 1997; Mariz, 1998; Processors, 2004)
The equipment of the process are sized for sweetening of 50 MMSCFD of the sour natural gas entering the unit for a better com-parison between the cases of using and not using the proposed synergy Aspen Economic Evaluation software is used for equip-ment sizing and cost estimation of the processes Based on the
0
10
20
30
40
50
60
70
Sour gas flow rate (MMSCFD)
increase in H2S increase in CO2
Fig 6 Enhancement in acid gas removal efficiency for scenario 2 at different sour
Table 3
Sweet gas composition in case of reaching pipeline specifications for the sweet gas.
in sweet gas after modification (solution flow rate 460 gpm)
Component mole fraction
in sweet gas before modification (solution flow rate 683 gpm)
0 200 400 600 800 1000 1200
Sour gas flow rate (MMSCFD)
aer modificaon before modifocaon
Fig 7 Variation of required solution flow rate with sour gas flow rate before/after modification to meet pipeline specifications of the natural gas.
Table 4 Effects of application of the proposed synergy on the equipment sizing and costs of the process.
process
Process using the proposed synergy Absorber inside diameter
(feet)
Regenerator inside diameter (feet)
Two phase separator height (feet)
Two phase separator inside diameter (feet)
Annual operating costs (million US$/year)
Total capital costs (million US
$)
Trang 6results of simulation and cost estimation, for the process which
uses the proposed synergy and the initial carbonate based process,
33% reduction in condenser duty and 31% cooler’s duty can be
obtained by applying the proposed synergy Also the reboiler duty
of the regenerator can face 27% reduction by applying the proposed
synergy Other important effects of application of the proposed
synergy are reported inTable 4
Experimental investigation of this change could be the next step
in evaluation of this change and finding other potential operating
problems
Conclusions
According to the results of this study, addition of sodium
hydroxide to the carbonate based solution increases the acid gas
removal capacity of the solution in the process of sweetening of
the natural gas Based on the required sweet gas specifications,
two scenarios are defined Scenario 1 in order to reach pipeline
specifications for the sweet natural gas, and scenario 2 in order
to reach 99.9% removal efficiency for the sweet gas Addition of
5.5 wt% of sodium hydroxide causes the CO2 and H2S removal
capacity of the solution to increase However, by addition of
sodium hydroxide to up to 12%, the removal capacity for H2S
remains the same while for CO2 increases The results of this
research show that when the pipeline specifications are the target
for the sweet natural gas, lower solution circulation rates would be
needed if the proposed modification on the solution is applied,
which will cause the equipment sizing, capital costs and energy
requirements of the process to decrease Another potential
advan-tage of this change on the solution can be extended applicability of
the Merox solution
Acknowledgements
Special thanks to dear friends Ahmad Mohmadi, Mojtaba
Malayeri, Milad Jafari, Aboozar Hasanvand, Mehdi Gholamrezayi,
Akbar Pashayi and Hessum Nikzad for their sincere helps during
this study
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