Article pubs.acs.org/EF
Influence of CO2 Residual of Regenerated Amine on the Performance of Natural Gas Sweetening Processes Using Alkanolamine Solutions Abolghasem Kazemi,* Ali Kazemi Joujili, Arjomand Mehrabani-Zeinabad, Zahra Hajian, and Reza Salehi Department of Chemical Engineering, Isfahan University of Technology, Isfahan 84156-83111, Iran ABSTRACT: In this research, three suitable alkanolamine solutions are selected for sweetening a natural gas with high H2S content and low CO2/H2S ratio. For each process, six different CO2 fractions in the regenerated solution are selected. On the basis of each CO2 fraction in the regenerated solution, the three processes are designed and simulated using the Aspen HYSYS process simulator to rich pipeline specifications (i.e., H2S content lower than 4 ppm and CO2 content lower than 2 mol %) for the sweet gas. The results of simulation are then economically evaluated using Aspen Economic Evaluation software. The results of simulation and economic evaluation indicate that the diglycolamine (DGA) process is more economical compared to monoethanolamine (MEA) and mixed methyldiethanolamine (MDEA) + MEA processes. Also, it is concluded that there are several advantages in operating the alkanolamine sweetening processes at higher CO2 fractions of the regenerated amine. On the basis of the results of this study, lower total capital costs, lower annual operating costs, and lower energy requirements for regeneration of the solution are obtainable by operating the alkanolamine sweetening processes at higher fractions of CO2 in the regenerated solution. In this research, we tried to answer two questions: “Which alkanolamine process exhibits the best economic performance in sweetening a natural gas having high H2S content and low CO2/ H2S ratio?” and “How does residual CO2 fraction in the regenerated alkanolamine solution influence the economic performance of the alkanolamine sweetening processes?”. In this study, the natural gas produced in a certain gas field with a high H2S content and low CO2/H2S ratio is considered and three suitable alkanolamine solutions are selected for sweetening a natural gas with a high H2S content and low CO2/H2S ratio. On the basis of the equilibrium H2S fraction in the gas stream (lower than 4 ppm to reach pipeline specifications), for each process, six different CO2 fractions in the regenerated solution are selected. On the basis of each CO2 fraction in the regenerated solution, the three processes are designed and simulated using the Aspen HYSYS process simulator to rich pipeline specifications for the sweet gas. The results of simulation are then economically evaluated using Aspen Economic Evaluation software.
1. INTRODUCTION Natural gas produced in oil and gas fields contains some concomitant components (e.g., H2S, CO2, and water vapor), which are sources of many problems, such as corrosion, low heating value, and natural gas hydrates in transmission lines.1−12 Therefore, these components should be separated from the natural gas before transmission through a pipeline. Purification of the natural gas from acid gases is called natural gas sweetening. Several processes, such as Sulfinol, Benfield, Shell, Amisol, Selefining, Purisol, Selexol, and alkanolamine processes, have been developed for acid gas removal from the natural gas.6,7,13−22 Alkanolamine processes are probably the most common processes used for sweetening the natural gas. Reactions R1−R6 occur when acid gases are absorbed in primary, secondary, and tertiary alkanolamine solutions.23−25 CO2 + 2R1NH 2 ↔ R1HCOO− + R1NH3+
(R1)
R1NH 2 + H 2S ↔ R1NH3+ + HS−
(R2)
CO2 + 2R 2NH ↔ R 2NH 2+ + R 2NCOO−
(R3)
R 2NH + H 2S ↔ R 2NH 2+ + HS−
(R4)
CO2 + R3N + H 2O ↔ R3NH+ + HCO3−
(R5)
R3N + H 2S ↔ R3NH+ + HS−
(R6)
2. FEED GAS SPECIFICATIONS In this research, 3.311 MSCMD of a low-pressure natural gas with a high H2S content and low CO2/H2S ratio is assumed. The H2S and CO2 fractions in the sour natural gas are 0.083 and 0.025, respectively. Therefore, the results of this research will be applicable for sweetening low-pressure natural gas with high H2S fractions. Other important specifications of the sour natural gas are shown in Table 1. Because the pressure of the sour natural gas is relatively low (as shown in Table 1) and the H2S fraction in the natural gas is high, on the basis of previous studies, the diglycolamine (DGA), monoethanolamine (MEA), and mixed methyldiethanolamine (MDEA) + MEA processes are selected
Each sweetening process has some advantages and disadvantages that make it suitable for certain conditions of sour and sweet gas target specifications.16,26−29 However, the costs associated with these processes are generally high, and reduction of costs of the alkanolamine processes has been the topic of a lot of studies. Effects of different parameters in the sweetening plants, such as lean amine temperature, stripper pressure, and process configuration, have been investigated in previous studies.6,30−38 © 2016 American Chemical Society
Received: February 4, 2016 Revised: April 15, 2016 Published: May 9, 2016 4263
DOI: 10.1021/acs.energyfuels.6b00295 Energy Fuels 2016, 30, 4263−4273
Article
Energy & Fuels
The amine DBR property package has been used for simulation. After completion of the simulation, the results are economically evaluated using Aspen Economic Evaluation software. The simulation flow sheet of the MEA process is shown in Figure 1. The absorber model is used for the contactor, and the distillation column model was used for the regenerator. The lean MEA solution and sour natural gas enter the absorber from the top and bottom stages, respectively. In the absorber, H2S and CO2 are transferred from the gas phase to the liquid phase. The rich MEA solution (containing H2S and CO2) and sweet gas are the bottom and top products of the absorber, respectively. Pressure of the rich MEA solution stream is then reduced to 1.67 atm in a valve, and some of the acid gases are separated from the solution in a two-phase separator. The rich MEA solution then passes a heat exchanger (approach temperature of 5 K) and is preheated before entering the regenerator column from stage 10. The top product of the regenerator column is mainly acid gases. The bottom product of this column is regenerated solution stream. This stream passes a heat exchanger, is mixed with the makeup solution stream, is pressurized to 18.71 atm, and is cooled to 308 K before entering the absorber for acid gas removal to complete the cycle. 3.2. DGA Process. DGA is a primary alkanolamine used for natural gas sweetening.17,50−53 DGA is more selective in absorbing CO2 from natural gas.16 However, having a high pH, DGA is able to reach pipeline specifications for the sweet gas.16,17,26 Also, having lower vapor pressures (in comparison to MEA), DGA can be used in higher concentrations.16 DGA concentrations between 40 and 70 wt % have been reported in previous studies.16,26 One of the disadvantages of DGA solution is its high heat of reaction with acid gases.26 DGA is a suitable solution for absorbing acid gases from low-pressure natural gas. An aqueous solution of 50 wt % DGA is selected for sweetening the natural gas. In this research, the DGA process is simulated using the Aspen HYSYS process simulator. The amine DBR property package has been used for simulation. After completion of the simulation, the results are economically evaluated using Aspen Economic Evaluation software. The simulation flow sheet of the DGA process is shown in Figure 2. The absorber model is used for the contactor, and the distillation column model was used for the regenerator. The lean DGA solution and sour natural gas enter the absorber from the top and bottom stages, respectively. In the absorber, H2S and CO2 are transferred from the gas phase to the liquid phase. The rich DGA solution (containing H2S and CO2) and sweet gas are the bottom and top products of the absorber,
Table 1. Feed Gas Specifications 1 2 3 4 5 6 7 8 9 10 11 12 13
property/component
value
temperature pressure flow rate H2O CO2 H2S methane ethane propane isobutane n-butane isopentane n-pentane
394.15 K 18.71 atm 3.311 MMSCMD 0.0102 0.0250 0.0830 0.8201 0.0402 0.0172 0.0014 0.0013 0.0007 0.0009
for sweetening the natural gas.7,16,17,19,26 The three processes are simulated to meet pipeline specifications for the sweet natural gas (which are
