For illustration, we will consider sweetening of 1.415 x 106<\/sup> std m3<\/sup>\/d (49.95 MMSCFD) of a sour natural gas with the composition, pressure, and temperature presented in Table 1. ProMax [6] simulation software with \u201cAmine Sweetening \u2013 PR\u201d property package was used to perform all the calculations. In addition, the mass + heat transfer option was used.<\/p>\n Table 1. Feed composition, volumetric flow rate and conditions<\/p>\n The following specifications\/assumptions were made:<\/p>\n Contactor Column<\/p>\n a. Feed sour gas is saturated with water<\/p>\n b. Number of actual stages = 23<\/p>\n c. Pressure drop = 35 kPa (5 psi)<\/p>\n d. Lean amine solution temperature = Sour gas feed temperature + 5.56 \u2103<\/em>\u00a0\u00a0(10 \u2109<\/em>)<\/p>\n Regenerator Column<\/p>\n a. Number of actual stages = 22 (excluding condenser and reboiler)<\/p>\n b. Rich solution feed temperature = 98.9 \u2103<\/em>\u00a0\u00a0(210 \u2109<\/em>\u00a0)<\/p>\n c. Rich solution feed pressure = 105 kPag (15.2 psig)<\/p>\n d. Condenser temperature = 48.9 \u2103<\/em>\u00a0\u00a0(120 \u2109<\/em>\u00a0)<\/p>\n e. Pressure drop = 35 kPa (5 psi)<\/p>\n f. Bottom pressure = 138 kPa (20 psig)<\/p>\n g. Reboiler duty = Specified \u201cSteam Ratio<\/em>\u201d times circulation rate (Refer to Table 2)<\/p>\n Heat Exchangers<\/p>\n a. Lean amine cooler pressure drop = 21 kPa (3 psi)<\/p>\n b. Rich side pressure drop= 41 kPa (6 psi)<\/p>\n c. Lean side pressure drop = 35 kPa (5 psi)<\/p>\n HP Pump<\/p>\n a. Discharge Pressure = Sour gas feed pressure + 35 kPa (5 psi) + \u0394PStatic<\/sub><\/p>\n \u0394PStatic<\/sub> = At least 130 kPa (19 psi) in just the elevation difference between the pump and the contactor inlet, plus some pressure drop on the FCV (unless you control flow via pump speed).<\/p>\n b. Efficiency = 65 %<\/p>\n Booster Pump<\/p>\n a. Discharge Pressure = Suction pressure + 55 kPa (8 psi) pressure drops in the L\/R exchanger and lean amine cooler and ensures the HP pumps have enough NPSHA.<\/p>\n b. Efficiency = 65 %<\/p>\n Lean Amine Circulation Rate and Concentration<\/p>\n a. Varied to meet the target acid gas loading in the rich solution shown in Table 2<\/p>\n Rich Solution Expansion Valves<\/p>\n a. \u0394P in the expansion valve to rich amine flash drum (valve 100) = 6310 kPa (915 psi)<\/p>\n b. \u0394P in the expansion valve to the stripper (valve 101) = 440 kPa (64 psi)<\/p>\n A simplified process flow diagram for the case studied is presented in Figure 1 [6].<\/p>\n Table 2. Specified amine concentration, target rich solution acid gas loading, and steam ratios [4]<\/p>\n Figure 1. Simplified process flow diagram for an amine sweetening unit [6]<\/p>\n Results and Discussions:<\/strong><\/p>\n Based on the description and specifications presented in the previous section, the process flow diagram in Figure 1 was simulated using ProMax BRE Software [6]. The simulation was performed for the steam ratio presented in Table 2. The results of the simulation are listed below:<\/p>\n – Treated sweet gas: H2<\/sub>S (3.98 ppmv) and CO2<\/sub> (0.948 mol %)<\/p>\n – Lean amine circulation rate: 669 std gpm (152 std m3<\/sup>\/h)<\/p>\n – Reboiler duty: 35.1 MMBtu\/hr (10.28 MW)<\/p>\n – Amine make-up: 0.315 lb\/hr (0.143 kg\/h)<\/p>\n – Water make-up: 646 lb\/hr (293 kg\/h)<\/p>\n The amine make-up is required to compensate for the amine vaporization losses from the top of the contactor, regenerator, and rich amine flash drum.\u00a0 The Promax program shows a blowdown stream on the amine, however it should be noted that this is not typically done in the field.\u00a0 Amine reclaimers are utilized today to recover amine solution quality rather than bleed and feed approach that was used in the past.\u00a0 The water make-up is required to maintain the water balance as the acid gas and flash gas remove water from the system.\u00a0 The operating conditions in the contactor will result in condensation or vaporization of water, but this is of really no concern as the amine solution is aqueous. Overall, water is generally lost from the amine solution in the acid gas stream and makeup water is required. This makeup water must be free of minerals and other contaminants, or it may become a means of introducing agents that cause foaming.<\/p>\n Figure 2 shows the feed sour gas phase envelope on dry basis. The calculated cricondentherm, cricondenbar pressures and temperatures are shown in Table 3.<\/p>\n Figure 2. Feed sour gas phase envelope.<\/p>\n Table 3. Sour gas calculated cricondentherm and cricondenbar pressures and temperatures<\/p>\n The gas from the facility inlet separator flowing to the AGR unit is at its hydrocarbon dewpoint at 90\u00b0F (32.2 \u00b0C) at pressure of 1000 psig (6,897 kPag). Any cooling occurring in the piping between the inlet separator and the process will result in hydrocarbon liquid and water condensation. Because the feed gas pressure is above the cricondentherm pressure, additional liquid hydrocarbons may be formed due to retrograde condensation associated with pressure drop in the piping. In addition, the gas leaving the inlet separator may also contain a small amount of liquid hydrocarbons and produced water due to separator carryover.<\/p>\n Installation of a properly sized filter coalescer upstream of the acid gas removal unit (AGR) unit is recommended, as shown in Figure 3 for an amine unit to minimize any potential liquid hydrocarbon or produced water carryover from entering the amine system. In some facilities the filter coalescer may be installed at a considerable distance from the contactor. When this happens, the condensation illustrated in Figure 2 can lead to solvent contamination and significant operating problems.<\/p>\n Figure 3. Process Flow Diagram for an Amine System Inlet [2]<\/p>\n To prevent hydrocarbon liquids condensation in the amine contactor, the lean amine inlet temperature should be roughly 5 to 10 \u00b0F (3 to 5 \u00b0C) warmer than the inlet sour gas. This temperature difference is referred to as the approach temperature (lean amine temperature approach to the inlet sour gas).\u00a0 Figure 4 presents the twenty-three actual-stages temperature profiles in the contactor column for two approach temperatures of 5, and 10 \u00b0F (2.8, and 5.6 \u00b0C)<\/p>\n Figure 4. Contactor gas-phase stage temperature profiles for two lean amine approaches to feed sour gas temperature<\/p>\n To check for possible hydrocarbon liquids condensation on a stage (or actual tray), the phase envelopes for the feed sour gas and the gas streams (on dry basis) leaving a few selected stages in the contactor column are illustrated in Figures 5 (FPS) and 6 (SI).<\/p>\n Figure 5-FPS. Process gas phase envelopes on dry basis in absorber (contactor) column for feed and selected stages.<\/p>\n Figure 6-SI. Process gas phase envelopes on dry basis in absorber (contactor) column for feed and selected stages<\/p>\n Note that as the acid gases are removed from process gas during its upward flow through the amine contactor, the gas hydrocarbon dewpoint curve shifts to the right and the two-phase region is expanded.\u00a0 Determining the required lean amine temperature approach requires knowledge of the phase envelopes of the gas as it flows through the contactor.\u00a0 Maintaining an adequate lean amine inlet temperature above the hydrocarbon dewpoint of the treated gas stream can aid in preventing foaming due to condensing liquid hydrocarbons.<\/p>\n Table 4 presents the estimated temperature values for a few selected points of Figures 5 and 6 based on the specified lean amine approach temperatures of 10 and 5 \u00b0F (5.6 and 2.8 \u00b0C) at the top of contactor and the feed sour gas temperature of 90 \u00b0F (32.2 \u00b0C).<\/p>\n Table 4. Estimated temperature margins for two lean amine approach temperatures<\/p>\n Notice that in the 10 \u00b0F (5.6 \u00b0C) case the stage operating temperature is to the right of (warmer than) the hydrocarbon dewpoint temperature by 8.0 \u00b0F (4.5 \u00b0C), thus no hydrocarbons vapor from gas stream condenses and solvent contaminations do not happen.<\/p>\n This is not the result for the 5 \u00b0F (2.8 \u00b0C) case (Figure 7).\u00a0 The inlet amine solution is slightly warmer than the hydrocarbon dewpoint temperature of the treated gas by 3.0 \u00b0F (1.7 \u00b0C) with a low safety factor. The potential would exist for some liquid hydrocarbon condensation if the amine were to cool slightly or if additional acid gases were removed from the gas stream.<\/p>\n![\"\"](\"https:\/\/i0.wp.com\/www.jmcampbell.com\/tip-of-the-month\/wp-content\/uploads\/2021\/09\/table1.png\")
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