Energy and performance optimization for H 2 S removal from sour gases in refinery units

Energy and performance optimization for H 2 S removal from sour gases in refinery units Thiago Vinícius Alonso Research and Development Engineer The Dow Chemical Company Abstract Fluid Catalytic Craking and Coker units designed to crack the long chain hydrocarbon molecules from the oil feed into shorter chain molecules, generates sour gas, very rich in hydrogen sulfide (H 2 S) a very poisonous component that must be treated in a efficient way. This removal is primarily done in amine units. For many years nearly all the amines units were using Monoethanolamine (MEA) or Diethanolamine (DEA). However in recent years, the use of tertiary solvents like Methyldiethanolamine (MDEA) has increased. The last solvents are generally less corrosive and require less energy to regeneration. Also some formulated solvents can have specific gas recoveries promoting carbon dioxide (CO 2 ) slip enhancing the performance of the unit in general. Having selectivity when removing H 2 S is very important to get a purer H 2 S stream where better performance of the Claus thermal oxidative unit is achieved as H 2 S is oxidized to elemental sulfur and CO 2 contaminants can allow the formation of sub products like (COS) carbonyl sulfide. At this work, a simulation of sour gas containing H 2 S and CO 2 is conducted using Dow Chemical s proprietary simulator with different solvents like MEA; DEA and UCARSOL HS 101. CO 2 slip was considerable greater for UCARSOL HS 101 enhancing the efficiency to treat the gas stream getting higher concentration of H 2 S in acid gas stream. Based on the results got for same conditions applied in all the solvents, UCARSOL HS 101 removed most of the H 2 S from sour gas with great advantage of slipping 75% of CO 2 and removing 95% of H 2 S present. Primary and secondary amines removed the H 2 S from sour gas without selectivity which showed a 20% higher presence of CO 2 in molar composition in the final acid gas stream. 1. Introduction The catalytic cracking, also known as FCC is a process where molecular breakdown is conducted being of great versatility and high profitability in refining transforming high molecular weight hydrocarbons into lighter products. The entrance stream is composed of a mixture of vacuum gas oil, deasphalted oil, and transformed into lighter fractions, such as fuel gas, liquefied gas, naphtha, gas oil (diesel cracking) and heavy gas oil cracking (Fuel oil). Usually coke is generated, which is deposited on the catalyst surface. Solvents based on chlorinated organic materials are used to regenerate the catalyst. This is a process designed, to maximize the production of high octane naphtha, as a major compound; secondly, LPG (Liquefied Petroleum Gas); and finally, in a few quantities appear cracking of diesel oil (CDO), oil cracking fuel oil (eluted /clarified), the fuel gas and acid gas (H2S) [1] [2]. The FCC unit can be divided in 4 sections. Reaction or Conversion Section is the first one where chemical reactions occur, assisted by a catalyst, in which the reagents are converted into products and recovery / regeneration of the catalyst happens. Fractionation Section is where there is separation of the reactor effluent in various products, recovery and recycle of the unconverted gasoil. The third section is the gas recovery where separation of light fractions converted according to petroleum cuts. The last stage is LPG and fuel gas treatment section: Treatment stage of petrol, LPG and fuel gas to provide for their marketing or further processing into other products, with a significant reduction in the sulfur content [2]. The Delayed Coking is a thermal cracking process widely used in the conversion of a fraction very undervalued, residue from the vacuum distillation, in other higher commercial value, such as LPG, naphtha, diesel and gasoil. The gasoil goes to the FCC unit [3]. In both units, mentioned above, gases are emitted such as H 2 S, CO 2, CO, COS (carbonyl sulfide) and others. Some of these gases are recovered in Gas Recovery Section, where Ethanolamines are used as scavenger 1

agent of pollutants. The removal of acid gas impurities, such as CO 2 and H 2 S, from sour gas streams is a significant operation in gas processing. Industrially important Ethanolamines for this operation are Monoethanolamine (MEA), Diethanolamine (DEA), Di-Isopropanolamine (DIPA), N-Methyldiethanolamine (MDEA) and Diglycolamine (DGA) [3] [4]. Nowadays formulated solvents have been preferred, due to increased selectivity to remove CO 2 or H 2 S spending less energy at regeneration stage. [4]. The main characteristics for the most used Ethanolamines today are described below. Monoethanolamine This is a primary amine, with just one organic substituent bounded to nitrogen. There is not so much selectivity with this amine. It removes H 2 S and CO 2 very aggressively. However it is very corrosive in concentrations above 18% weight/weight in the presence of CO 2 to form carbamates that degrade into coordination agents increasing corrosion problems and usually need reclamation units to recover HSAS (Heat Stable Salts). Diethanolamine This is a secondary amine, with just two organic substituent bounded to nitrogen. This amine removes H 2 S and CO 2 and also COS. Typically used in concentrations of 30% wt or less and can decompose in the presence of CO 2 to form degradation compounds from carbamates increasing corrosion problems. Methyldiethanolamine This is a tertiary amine, with three organic substituent bound to nitrogen. Has a higher affinity for H 2 S than CO 2 which allows some CO 2 slip. Has a low heat of reaction comparing to primary and secondary amines, which represents lower energetic costs for regeneration. Carbamates are not formed and concentration up to 45% wt. can be used. [5] UCARSOL - FORMULATED SOLVENTS UCARSOL solvents are formulated products that can work for specific customer s desired application in a very efficient way. These products allow low required regeneration energy comparing to conventional amines and corrosion problems are much reduced. These tailored solvents were developed for bulk CO 2 removal, H 2 S removal with CO 2 slip and many other applications for natural gas and refineries gas sweetening plants. [6] The choice of each ethanolamine is based in its selectivity, which depends on the pressure and temperature conditions at which the gas to be treated is available. As an example of Ethanolamines, MEA is used at low pressures and low concentrations, and promotes high alkalinity. Chemically MEA makes irreversible products with COS and CS 2 and this one of the main sources of HSAS generated. However, it is appreciably more corrosive than other Ethanolamines [7]. On the other hand, DEA, is much less reactive with COS and CS 2 than primary amines. The reaction products are not so corrosive, and it is used in treatment of refinery gases which in general contain considerable amounts of COS and CS 2, besides H 2 S and CO 2. One disadvantage is that DEA undergoes numerous irreversible reactions with CO2, forming corrosive degradation products, and for this reason, DEA may not be the optimum choice for treating gases with a high CO 2 content. Gas treatment using MDEA-based solutions, under the trade name of UCARSOL HS Solvents, are claimed to be more selective than conventional MDEA and DIPA solutions and, consequently, more economical with respect to energy consumption [8] 2

The chemical neutralization reactions are represented by the equations below, extracted from Gas Purification handbook: H 2 S + Amine [Amine]H + + HS CO 2 + H 2 O + Amine [Amine]COOH + + OH CO 2 + H 2 O + R 2 NCH 3 R2NCH4 + + HCO3 CO 2 + H 2 O HCO 3 + H + HCO 3 - CO 2 2- + H + H 2 O OH + H + RR'R'NH + RR'R'N + H + H 2 S HS + H + HS S 2 + H + At this work, it is shown a gas treating system working with UCARSOL HS 101, a formulated amine designed to remove high levels of H 2 S with CO 2 slip where sweet gas has a specification of 0.25% mol maximum of H 2 S. 2. Materials and Methods Results were obtained using DOW s proprietary simulation software PROCOMP. The simulator solves the material balances, heat balances, mass transfer relations and equilibrium relations necessary to perform rigorous rate based calculations on absorbers and strippers. Other equipment such as heat exchangers, pumps and flash tanks, can also be simulated. All vapor liquid equilibrium values are screened and fitted when necessary to ensure that simulator matches experimental data. 3. Results and Discussion In this situation the sweet gas must achieve 0.25% mol of H 2 S maximum. The amount of CO 2 desired in sweet gas is maximized in order to increase CO 2 slip and to get a richer H 2 S composition in the acid gas stream. The sour gas composition from FCC and Coker units in molar percentage and its characteristics are below: FCC Stream: CO 2 : 3.40 H 2 S: 4.70 H 2 : 11.70 N 2 : 14.90 CH 4 : 26.45 Ethane: 19.75 Ethylene: 10.00 Propane: 1.10 Propylene: 6.50 Others: 1.50 Temperature: 27.0 C Pressure: 13.0 bar (g) Flow rate: 1.88. 10 5 SCMD 3

COKER Stream CO 2 : 0.20 H 2 S: 3.60 H 2 : 8.00 N 2 : 0.20 CH 4 : 62.70 Ethane: 15.90 Ethylene: 2.90 Propane: 3.70 Propylene: 2.80 Temperature: 16.0 C Pressure: 8.6 bar (g) Flow rate: 199. 10 5 SCMD The gas treating plant simulated in this case has 2 absorber towers and one stripper. The characteristics for each tower are described below. FCC Absorber Column: - Diameter: 3.61 ft - Active tray Area: 8.18 ft 2 - Number of Trays: 28 - Tray Spacing: 610 mm - Weir height: 2 in - Internals: Generic Valve Trays COKER Absorber Column: - Diameter: 3.61 ft - Active tray Area: 8.69 ft 2 - Number of Trays: 28 - Tray Spacing: 650 mm - Weir height: 2 in - Internals: Generic Valve Trays Regenerator Column: - Diameter: 4.59 ft - Active tray Area: 13.25 ft 2 - Number of Trays: 20 - Tray Spacing: 610 mm - Weir height: 2 in - Internals: Generic Valve Trays 4

The flowchart of the process is described in figure 1 below. Figure 1. Flowchart of the simulated plant In this case, the FCC and Coker gas comes saturated in equilibrium condition with water. The inlet temperature is 27 C and 16 C respectively. The inlet gas enters the bottom section of the amine contactors. The rich amine enters the amine regeneration system feeding into the amine flash tank. The amine flash tank is designed to provide 3 minutes of residence time. The liquid solution from the amine flash tank flows through a lean/rich exchanger where rich amine is preheated before moves into the stripper and lean amine is cooled before it goes to cooler. The rich amine is fed at the top stage of the regenerator column. A water cooled heat exchanger is provided for the reflux condenser and a horizontal vessel serves as the reflux accumulator. The acid gas vapors of the reflux accumulator moves for its final disposal. At the bottom of the amine regenerator, heat duty is provided in the reboiler with saturated steam or hot oil. The lean amine that leaves the stripper is divided in two different streams. The stream number three is cooled using an air cooler to drop solution temperature to around 40 o C. The stream number two that goes to FCC absorber tower and does not need air cooler as the temperature loss during the pipeline transmission is enough to achieve temperature around 30 o C. The lean amine streams are pumped into the absorber column where it reacts with acid gases. For an efficient gas treating system, a key factor of success is to have controlled the degradation levels of amine, keep under control the corrosion rate of pipelines, to manage the amount of energy spent mainly for the regeneration process and for cooling, heating operations, and pumping activities and most importantly, leaving the sweet gas under desired specification limits. The simulation was conducted in this case with regular commodities amines like MEA (Monoethanolamine), DEA (Diethanolamine) and also with formulated solvent UCARSOL HS 101, a product with high selectivity for H 2 S removal. Solvents concentration in water followed the conventional guidelines for each amine. For MEA it was used a concentration of 15% wt, for DEA a concentration of 30% wt; and for UCARSOL HS 101 a concentration of 45% wt. 5

Some operational characteristics of the simulated gas sweetening plant are described in table 1. The simulation was conducted for all the solvents using these fixed properties. The circulation rate is one of the most important factors to be considered as circulation rate is increased for any given column, the CO 2 and H 2 S removal will increase due to higher amount of amine moles available to react with acid gases in a certain time. Table 1 Process conditions for simulation Absorber Tower 1 Pressure bar (g) 13.0 Absorber Tower 2 Pressure bar (g) 8.6 Flash tank residence time (min) 3.0 Regeneration Pressure bar (g) 1.8 Reboiler Heat Duty (MMBTU/h) 12.0 Amine circulation rate (m 3 /h) 15.0 Percentage of total amine flow - Stream 2 55.0 Percentage of total amine flow - Stream 3 45.0 Regenerator condenser temperature (ºC) 40.0 At table 2 below, it is shown the treated gas condition for all the solvents at the streams of sweet gas produced. Table 2 Sweet gas characteristics MEA DEA UCARSOL HS 101 Stream FCC COKER FCC COKER FCC COKER Temperature (ºC) 65 64 39 49 42 50 Pressure (bar a) 13.6 9.3 13.6 9.3 13.6 9.3 Amine concentration (%wt) 15 15 30 30 45 45 Molar Flow (kmol/hr) 339 361 321 358 331 360 Water (mol fraction) 1.70. 10-2 1.83. 10-2 4.15. 10-3 1.06. 10-2 4.69. 10-3 1.05. 10-2 CO 2 (mol fraction) 9.53. 10-3 4.61. 10-6 3.86. 10-5 4.08. 10-5 2.55. 10-2 1.56. 10-3 H 2 S (mol fraction) 2.92. 10-2 1.18. 10-7 6.94. 10-5 8.74. 10-9 2.07. 10-3 1.62. 10-3 Hydrogen (mol fraction) 1.20. 10-1 8.16. 10-2 1.27. 10-1 8.22. 10-2 1.23. 10-1 8.20. 10-2 Nitrogen (mol fraction) 1.53. 10-1 2.04. 10-3 1.61. 10-1 2.06. 10-3 1.57. 10-1 2.05. 10-3 Methane (mol fraction) 2.72. 10-1 6.40. 10-1 2.87. 10-1 6.45. 10-1 2.78. 10-1 6.42. 10-1 Ethane (mol fraction) 2.03. 10-1 1.62. 10-1 2.14. 10-1 1.63. 10-1 2.08. 10-1 1.63. 10-1 Ethylene (mol fraction) 1.03. 10-1 2.96. 10-2 1.08. 10-1 2.98. 10-2 1.05. 10-1 2.97. 10-2 Propane (mol fraction) 1.13. 10-2 3.77. 10-2 1.19. 10-2 3.80. 10-2 1.16. 10-2 3.79. 10-2 Propylene (mol fraction) 6.67. 10-2 2.86. 10-2 7.04. 10-2 2.88. 10-2 6.84. 10-2 2.87. 10-2 Others (mol fraction) 1.53. 10-2 1.55. 10-4 1.64. 10-2 4.99. 10-4 1.67. 10-2 9.70. 10-4 By the results obtained, it can be seen that UCARSOL HS 101 let the sweet gas from FCC unit with 2.55% of CO 2 and 0.20% of H 2 S in its composition. For the Coker unit residual CO 2 is around 0.15% and 0.16% of H 2 S. Gas specification is covered in all these cases but CO 2 slip for UCARSOL HS 101 is much higher when 6

comparing molar fractions of this component in sweet gas streams from units using MEA and DEA. The CO 2 Slip percentage and H 2 S absorption are described in table 3 below: Table 3 Percentage of CO 2 Slipped and H 2 S Removed Streams MEA DEA UCARSOL HS 101 %CO 2 Slip FCC 28.0 0.11 75.0 %CO 2 Slip - Coker 0.23 2.04 78.0 %H 2 S Removed - FCC 37.8 99.8 95.6 %H 2 S Removed - Coker 100 100 95.5 It can be clear seen the solvent selectivity in table 3. MEA removes H 2 S efficiently for Coker stream which has low amount of CO 2. However in the situation where CO 2 composition is higher like in FCC stream most of the amine will react with this gas reducing the amount of suitable molecules to react with H 2 S. For this reason CO 2 slip is low and lower amounts of H2S are removed, as the solvent has no selectivity. The opposite situation happens with UCARSOL HS 101 as the material has a huge selectivity for H 2 S, most of the CO 2 does not react with it and the solvent reacts mostly with H 2 S. In table 4, the results for simulation are described for the acid gas stream. Table 4 Acid gas characteristics MEA DEA UCARSOL HS 101 Temperature (ºC) 40 40 40 Pressure (bar a) 2.5 2.5 2.5 Molar Flow (kmol/hr) 30 43.5 32.9 Water (mol fraction) 0.029 0.029 0.029 CO2 (mol fraction) 0.312 0.288 0.108 H 2 S (mol fraction) 0.657 0.681 0.861 Residual Hydrocarbons (mol fraction) 0.002 0.002 0.002 The acid gas produced by this system considering the solvents studied shows UCARSOL HS 101 slipped more CO 2 in absorber tower allowing a better efficiency to remove H 2 S as can be seen the higher molar fraction of this component when comparing to other units using primary and secondary amines. A richer H 2 S stream is very desirable in order to maximize productivity and avoid presence of inert components and sub products production in the Claus thermal oxidative unit. The analysis of rich and lean amine loadings were conducted also. The molar concentration of acid gases per moles of amine is described to be the loadings. The rich amine has a high concentration of acid gases and it is found at the stream that flows out the absorber column. The lean amine has a low concentration of acid gases and it is found at the stream that flows out the regenerator column. To avoid corrosion problems, these loadings must be under certain specified values. Also, the maximum temperature of lean amine must be below 135 C to avoid solvent degradation and corrosion issues. The conditions for rich/lean amine are found in table 5, table 6 and table 7. 7

Table 5 Lean/Rich amine streams for MEA Lean loading mol CO 2 /mol MEA 8.89. 10-3 Lean loading mol H 2 S/mol MEA 1.74. 10-4 Hot Lean amine temperature (ºC) 133 Cold Lean amine temperature (ºC) 66 Rich loading mol CO 2 /mol MEA 0.267 Rich loading mol H 2 S/mol MEA 0.546 Hot Rich amine temperature (ºC) 100 Cold Rich amine temperature (ºC) 45 Table 6 Lean/Rich amine streams for DEA Lean loading mol CO 2 /mol DEA 5.19. 10-3 Lean loading mol H 2 S/mol DEA 4.47. 10-7 Hot Lean amine temperature (ºC) 134 Cold Lean amine temperature (ºC) 80 Rich loading mol CO 2 /mol DEA 0.299 Rich loading mol H 2 S/mol DEA 0.693 Hot Rich amine temperature (ºC) 100 Cold Rich amine temperature (ºC) 49 Table 7 Lean/Rich amine streams for UCARSOL HS 101 Lean loading mol CO 2 /mol UCARSOL HS 1.98. 10-4 Lean loading mol H 2 S/mol UCARSOL HS 1.71. 10-3 Hot Lean amine temperature (ºC) 135 Cold Lean amine temperature (ºC) 65 Rich loading mol CO 2 /mol UCARSOL HS 6.31. 10-2 Rich loading mol H 2 S/mol UCARSOL HS 0.500 Hot Rich amine temperature (ºC) 100 Cold Rich amine temperature (ºC) 39 The rich loading for UCARSOL system was around 0.063 moles CO 2 /mole of amine and for the commodity amines it was found a value around 0.28 moles CO 2 /mole of amine representing more removal of CO 2 from the sour gas in the absorber columns. Cold rich streams temperatures also shows that MEA and DEA reaction with acid gases were more exothermal as temperatures are higher when comparing to UCARSOL HS 101. Higher energies released in absorber tower must be applied back in regeneration unit to break the amine salt formed and to release acid gases. This can demand more energy spent in reboilers. It is important to keep lean loading below 0.01 moles acid gases/mole of amine. High lean loadings and solution degradation products can lead to corrosion and reboiler fouling problems. At the same way, it is important to keep the rich loadings around 0.4 to 0.5 moles acid gases/mole of amine in order to optimize acid gases removal. [8] The lean loading for all the cases studied is considerably low, as it indicates that over regeneration in stripper happened. As the steam-stripping rate is increased, a leaner amine will be produced which can result in a greater distance to equilibrium and more acid gases can be removed from the sour gas. However it is very important to consider that over regeneration can generate corrosion problems as well and promote low energetic efficiency. 8

4. Conclusions By the results observed, UCARSOL HS 101 showed a very efficient performance to remove H 2 S in a refinery gas treating unit where sour gases are from FCC and Coker facilities. The main characteristic of the system running with formulated solvent is the greater CO 2 slip in the absorber towers. Considering that, in the acid gas stream H 2 S presence was richer which can enhance the productivity of Claus thermal oxidative unit and reduce the formation of sub products. MEA showed good H 2 S removal when CO 2 was not present and the opposite characteristic when CO 2 was in higher concentration. DEA removed efficiently H 2 S but also removed most of the CO 2 present in sour gas showing no selectivity. It can be seen that primary and secondary amines have no selectivity for H 2 S removal, removing both acid gases in similar rates. It was observed high rich loadings for CO 2 for the primary and secondary amines while it was almost five times lower for UCARSOL HS 101. Rich loading for H 2 S was similar for all the amines studied. The cold rich amine stream also showed lower temperature for UCARSOL HS 101 representing that less energy was released in acid-base reaction. Lower energy in absorption process means lower energy to be spent at the regeneration unit. 5. References [1] ABADIE, E. Refining Process: Formation course of refinery operators. PETROBRAS/SEREC/CEN-SUD, Curitiba, 2002. [2] DANTAS NETO, A. A.; GURGEL, A. Oil Refining and Petrochemical course. Federal University of Rio Grande do Norte - Technology Center - Department of Chemical Engineering. [3] ROCHA, L. S. Dynamic simulation and optimization of Delayed Coking Unit in oil refinery. UNICAMP, Campinas, 2011. [4] KOHL, ARTHUR L.; NIELSEN, RICHARD B. Gas Purification, 5th Edition. Ed. Elsevier, 1997 chapter 2. [5] SAAR, R et al, An Operational Comparison of DEA Versus Formulated High Performance Selective Amine Technology, CGPA/CGPSA Third Quarterly Meeting [6] UCARSOL AP-814 for CO2 removal Product information [7] Amine Treating: Amine Gas Sweetening and Amine Unit. Available in: http://www.newpointgas.com/amine_treating.php. Accessed in July, 22th 2012. [8] MANDAL, B.P.; BANDYOPADHYAY, S.S. Simultaneous absorption of carbon dioxide and hydrogen sulfide into aqueous blends of 2-amino-2-methyl-1-propanol and diethanol amine, Chemical Engineering Science, 2005. 9