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Journal of Unconventional Oil and Gas Resources 14 (2016) 6–11 Contents lists available at ScienceDirect Journal of Unconventional Oil and Gas Resources journal homepage: www.elsevier.com/locate/juogr Synergy between two natural gas sweetening processes Abolghasem Kazemi a,⇑, Abolfazl Gharibi Kharaji b, Arjomand Mehrabani-Zeinabad a, Vafa Faizi b, Jalalaldin Kazemi c, Ahmad Shariati d a Chemical Engineering Department, Isfahan University of Technology, Isfahan, Iran Chemical Engineering Department, University of Isfahan, Isfahan, Iran c Computer and Science Engineering Department, Shiraz University, Shiraz, Iran d Natural Gas Engineering Department, Petroleum University of Technology, Ahwaz, Iran b a r t i c l e i n f o Article history: Received 11 September 2014 Revised 27 November 2015 Accepted January 2016 Available online February 2016 Keywords: Carbonate based processes Natural gas sweetening Merox process CO2 removal 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 CO2 from natural gas is a wellknown 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 facilities 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 transmission are ppm and mol%, respectively (Kidnay and Parrish, 2006; Kohl, 1997) Gas sweetening processes of industrial gas treating plants must provide (a) complete removal of H2S, (b) handling 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 synergy 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 ⇑ Corresponding author Tel.: +98 9171492783 E-mail address: abolghasemkazemi@gmail.com (A Kazemi) http://dx.doi.org/10.1016/j.juogr.2016.01.002 2213-3976/Ó 2016 Elsevier Ltd All rights reserved the mixed amine processes a mixture of tertiary amines and secondary (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 combines 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 CO2 and also in presence of SO2 it 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) NaOH ỵ H2 S $ NaHS ỵ H2 O 2NaOH ỵ H2 S $ Na2 S ỵ 2H2 O 2NaOH ỵ CO2 $ Na2 CO3 ỵ H2 O ð1Þ A Kazemi et al / Journal of Unconventional Oil and Gas Resources 14 (2016) 6–11 Merox 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 CO2 according to reaction (2) is an important and well-known fact: In accordance to Table 1, there is 0.2 mol% of C7+ in the feed gas As this hydrocarbon cut contains hydrocarbon molecules with or more carbons, in the simulation environment normal octane was used instead K2 CO3 ỵ CO2 ỵ H2 O $ 2KHCO3 The simulation was performed based on a flow sheet as presented in Fig 1, however an industrial unit might have different unit operations based on the sour gas conditions and the specifications required for the sweet gas (Chowdhury, 2013) According to Fig 1, the sour gas at 40 °C and 22 atm enters the bottom of absorber unit The carbonate solution at 116 °C and 26 atm enters the absorber at the top stage In the absorber based on reaction (2) CO2 and H2S of the natural gas are absorbed by the solution The sweet gas leaves the absorber with low H2S and CO2 mole 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 atm and 101 °C The two phase separator operates under these operational 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 ð2Þ Considering these facts, this study investigate a possible synergy 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 to Table 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 transfer 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) Nevertheless, 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 Table The sour gas composition Component Mole% CH4 C2H6 H2O H2S CO2 C3H8 i-butane N-butane i-pentane N-pentane N-hexane C7+ Total 74.2 10.9 0.1 5.7 5.6 2.3 0.3 0.2 0.2 0.15 0.15 0.2 100 Process description 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 calculated If the applied changes not affect the H2S and CO2 removal efficiencies, then the proposed synergy fails But upon variation of removal efficiencies of the acid gases, a comprehensive interpretation of the results is needed to evaluate the synergy Having this procedure in mind, 10 MMSCFD of the introduced natural gas in Table was processed with lean solution modified with sodium hydroxide at various concentrations The process removal efficiencies are reported in Table and Fig As indicated in Table and Figs and 3, upon addition of sodium hydroxide to the lean solution, the H2S and CO2 mole fractions in the sweet gas decreased The fraction of H2S in the sweet gas reduced to a minimum (less than ppm) at sodium hydroxide weight percent of 5.5%, the mole fraction of CO2 in the sweet gas reached a minimum (less than 0.1%) for sodium hydroxide concentration 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 CO2 in 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 CO2 and 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 A Kazemi et al / Journal of Unconventional Oil and Gas Resources 14 (2016) 6–11 Fig Simulation flow sheet Table Effects of applying the proposed change on the H2S fraction of the processed gas wt% of added modifier Solution GPM Ppm of H2S in processed gas Constant Increased Constant Increased 0.1 0.2 0.5 0.7 10 15 20 114.0 114.0 114.0 114.0 114.0 114.0 114.0 114.0 114.0 114.0 114.0 114.0 114.1 114.3 114.6 114.8 115.1 116.2 119.7 125.4 131.1 136.8 52.3 47.8 43.9 33.9 28.5 22.1 9.6 0.7 0.5 0.4 0.2 52.3 47.8 43.7 33.4 28.0 21.5 9.0 0.7 0.5 0.4 0.2 Effects of solution modification higher 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 materials like stainless steel grade 304 (UNS S30400) or stainless steel mole fracƟon of CO2 in the processed gas grade 316 (UNS S31600) or polysulfone which are resistant to corrosion 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 introduced grade of stainless steel for construction, application of this change can expand the operability of the process As indicated in Table 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 CO2 became 52 ppm and 0.0362, respectively According to these data the removal efficiency of H2S and CO2 are 99.9% and 35.5%, respectively At this point, two scenarios can be defined for meticulously analyzing 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 and Table that upon increasing the concentration of sodium hydroxide in solution to 5.5%, the pipeline specifications for the H2S and CO2 are 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, respectively Removal efficiencies were extended to 99.9% and 83.9% for 0.045 0.04 0.035 0.03 0.025 0.02 0.015 increased soluƟon GPM 0.01 Constant soluƟon GPM 0.005 0 0.05 0.1 0.15 0.2 0.25 wt% of the modifier added Fig Effect of application of the proposed change on the residual acid gas in the processed gas stream 9 A Kazemi et al / Journal of Unconventional Oil and Gas Resources 14 (2016) 6–11 Acid Gas removal efficiency (%) 1.2 0.8 0.6 H2S removal efficiency - Increased soluƟon GPM 0.4 H2S removal efficiency - Constant soluƟon GPM CO2 removal efficiency- Increased soluƟon GPM 0.2 CO2 removal efficiency - Constant soluƟon GPM 0 0.05 0.1 0.15 0.2 0.25 wt% of the modifier added Fig Effect of application of the proposed change on the acid gas removal efficiencies Scenario 2: 99.9% removal of CO2 and H2S Another scenario is defined to reach 99.9% removal of both CO2 and H2S in the sweetening process Some of applications of natural 60 Acid gas removal efficiency (%) H2S and CO2, respectively Thus, applying the proposed modification on the carbonate based solution, for flow rate of 40MMSCFD of sour gas, results in the removal efficiency of CO2 to be increased by approximately 50% The simulation also was carried out for other flow rates of sour gas, For 20, 30, 50 and 60 MMSCFD the results are presented in Figs and Fig shows 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 in Figs and is 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 parameter which can take a part in the decisions concerning the application of this change 50 40 increase in H2S increase in CO2 30 20 10 20 25 30 35 40 45 Acid Gas Removal efficiency (%) for scenario1 H2S (aŌer soluƟon modificaƟon) increase in CO2( aŌer soluƟon modificaƟon) CO2 ( without soluƟon modificaƟon) 60 40 20 30 35 60 gas require the sweet natural gas with extremely low CO2 concentrations (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 in Fig 3, upon addition of 12% of sodium hydroxide to the solution, 99.9% of CO2 and H2S removal are achievable and the concentration of CO2 falls lower than 0.1% Enhancement in removal efficiency of CO2 and H2S are shown in Fig 80 25 55 Fig Increase in acid gas removal efficiency for scenario at different sour gas flow rates 100 20 50 Sour gas flow rate (MMSCFD) 40 45 50 55 Sour gas flow rate (MMSCFD) Fig Variation of acid gas removal efficiency with sour gas flow rates for scenario 60 10 A Kazemi et al / Journal of Unconventional Oil and Gas Resources 14 (2016) 6–11 Table Sweet gas composition in case of reaching pipeline specifications for the sweet gas Component Component mole fraction in sweet gas after modification (solution flow rate 460 gpm) Component mole fraction in sweet gas before modification (solution flow rate 683 gpm) C2H6 CH4 O2 CO2 H2S N2 H2O C3H8 Isobutane Normal butane Isopentane Normal pentane Normal hexane Normal octane 0.097 0.816 0.017 0.0009 0.5 ppm 0.006 0.002 0.044 0.004 0.009 0.002 0.002 365 ppb 29 ppb 0.097 0.816 0.017 0.0009 ppm 0.006 0.002 0.044 0.004 0.009 0.002 0.002 355 ppb 27 ppb Before modification of the solution for the removal of H2S and CO2 from the specified natural gas (Table 1), to meet pipeline specifications, 683.4 gallons per minute of the sorbent solution is needed, based on the simulation results After improving the solution, 460.4 gallons per minute of the solution are required for reducing H2S and CO2 content of the natural gas to the permission level according to pipeline specifications The simulation results for the sweet gas are shown in Table As indicated in Table 3, in order to reach a specific concentration 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 equipment would be smaller which results in reduction of the plants total capital and operating costs (Kazemi et al., 2014) Also the possibility 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 recommended prior to application of this modification in natural gas sweetening units Fig shows that in order to reach pipeline specifications for the sweet gas, at a specific flow rate of the sour gas, the required circulation rate of the modified solution is decreased 1200 1000 800 600 aŌer modificaƟon before modifocaƟon 400 200 20 25 30 35 40 45 50 55 60 Sour gas flow rate (MMSCFD) Fig Variation of required solution flow rate with sour gas flow rate before/after modification to meet pipeline specifications of the natural gas According to Figs 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 circulation 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 comparison between the cases of using and not using the proposed synergy Aspen Economic Evaluation software is used for equipment sizing and cost estimation of the processes Based on the Table Effects of application of the proposed synergy on the equipment sizing and costs of the process 70 Acid gas removal efficiency (%) Required soluƟon flow rate (gpm) Effects of changing the solution (to meet pipeline specifications) 60 50 increase in H2S increase in CO2 40 30 20 10 20 25 30 35 40 45 50 55 60 Sour gas flow rate (MMSCFD) Fig Enhancement in acid gas removal efficiency for scenario at different sour gas flow rates Parameter Carbonate based process Process using the proposed synergy Absorber inside diameter (feet) Absorber height (feet) Regenerator inside diameter (feet) Regenerator height (feet) Two phase separator height (feet) Two phase separator inside diameter (feet) Annual operating costs (million US$/year) Total capital costs (million US $) 5 70 70 42 24 42 22 7.5 4.90 4.42 6.72 6.19 A Kazemi et al / Journal of Unconventional Oil and Gas Resources 14 (2016) 6–11 results 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 in Table 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 in order to reach pipeline specifications for the sweet natural gas, and scenario 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 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