Amine strength in gas treatment
Tail gas treating units (TGTUs) are designed to remove the last vestiges of unconverted hydrogen sulfide (H2S) in the tail gas coming from a sulfur recovery unit (SRU) after the gas has been processed to convert as much H2S as possible to elemental sulfur. Any H2S remaining in the TGTU’s offgas is converted to sulfur dioxide (SO2) in the thermal oxidizer and vented to the atmosphere. This vented SO2 forms part of a plant’s regulated sulfur emissions, so it is important to minimize its amount.
H2S in the treated gas from the TGTU usually ranges from < 10 parts per million (ppm) up to a few hundred ppm by volume. This is the typical range of SO2 levels emitted from the plant’s stack. Due to the very low pressures at which TGTU absorbers operate (essentially atmospheric), meeting the rigorous standard on TGTU performance for low-ppm H2S outlet values can be difficult to achieve.
This article is guided by the example of a refinery TGTU that was treating gas with 1.5 mol% H2S and 4.2 mol% carbon dioxide (CO2) at 1.5 psig with a solvent designed specifically for tail gas treatment. Amine suppliers have developed specialty solvents designed to make very-low-sulfur vent rates easier to achieve in this and other low-pressure applications. This refinery uses a methyldiethanolamine (MDEA)-based solvent with an additive that functions to enhance H2S removal to extremely low levels. The physical properties of the solvent are quite similar to MDEA.
The unit consisted of two separate tail gas systems, each feeding 13-tray, 9-ft diameter absorbers with 2-pass trays served by a common, dedicated regenerator. A second regenerator was available to tie into the system. At a weir liquid load of about 16.6 gal/min/ft, the absorber trays were operating well into the spray regime. The normal solvent strength during standard operations was 40 wt%.
At this refinery, an SO2 breakthrough occurred where upstream upsets caused SO2 to slip past the hydrogenation reactor in the TGTU. This resulted in SO2 rather than H2S being sent to the TGTU amine absorbers. One consequence of a breakthrough is that SO2 will react with any amine to form degradation products called heat stable salts (HSSs).
Following the breakthrough, the HSS level in the solvent had risen to a concerning level. It was decided to purge a part of the amine solution and replace it with fresh solvent to lower the HSS concentration to an acceptable level. Fresh solvent is received almost without water (H2O) so when adding makeup, it is necessary to include 60 parts by weight of H2O with 40 parts virgin solvent to provide 40 wt% replacement solvent.
Although the SO2 breakthrough was a short-term, symptomatic event and did not directly result in H2S treating issues, unintended consequences were caused by the solution purge and solvent make-up. How did this result in high SO2 values from the incinerator? In part, the answer coincides with the basis on which the solvent strength was made up and the resulting high amine concentration in the solution.
FIG. 1 shows the treating history around the time of the solvent purge-and-replacement event. Prior to this, one TGTU was producing about 100-ppmv SO2 in the stack gas, while the other produced only 50-ppmv SO2. The cause of the change was quickly discovered: the operators had forgotten to dilute the virgin solvent with H2O, so the purged volume (40 wt% amine) had been replaced by an equal volume of pure, undiluted solvent. This resulted in the solvent strength increasing to 57 wt%, which caused the SO2 emissions to increase to 350 ppmv–450 ppmv. Had this been allowed to continue, the sulfur units would have been in violation of environmental regulations.
FIG. 1. SO2 stack emissions from the two TGTUs around the time of the excursion.
TABLE 1 shows how certain performance parameters change with the observed loss in performance. Overall, the changing observed performance runs contrary to conventional wisdom in that higher strength solvents are expected to perform better, not worse. So, what happened, and what lessons can be learned?
Analysis. Solvent suppliers make recommendations for the maximum allowable amine strength for use in gas treatment. For example, monoethanolamine (MEA) is normally recommended with a 20 wt% limit [except in carbon capture, where 30% and 40% seem to be permissible (in combination with corrosion inhibitors)], diethanolamine (DEA) is limited to 40 wt% and MDEA is limited to about 50 wt%. However, this does not mean that these amines are recommended to be used at maximum recommended strengths, although that seems to be the general—and sometimes mistaken—interpretation of gas treaters. Low-strength solvents sometimes can be more efficacious.
Conventional thinking is to use maximum amine strength because high amine concentrations absorb acid gases faster due to faster reaction kinetics and higher vapor-liquid equilibrium (VLE) capacity. However, this does not always result in the best treating outcomes. Reaction kinetics and VLE are not the only factors that affect rates of absorption in treating solvents. The process of getting the gas to the solvent interface is diffusional, as is getting the dissolved gas from the interface into the bulk solvent.
Although solvents at higher strength have faster reaction kinetics and, therefore, faster absorption rates, they are more viscous—high-viscosity solvents have poor diffusional ability, which can be important for the absorption of diffusion-limited species such as CO2. In tail gas treating, CO2 absorption is to be minimized, as it is detrimental to H2S absorption because it reduces the solvent’s capacity to absorb H2S.
FIGS. 2 and 3 show the results of simulations of the two absorbers immediately before and after the addition of fresh solvent makeup. As shown in TABLE 1, the simulated and observed H2S content of the treated gas are quite close, and the viscosity of the higher strength solvent is directionally as expected. These simulations closely account for the performance of the absorbers before and after the solvent purging and makeup event; however, like the data, they run counter to expectations. Higher amine strengths do not result in better treatment, even when the lean amine loadings are lower.
FIG. 2. H2S emissions from the two TGTUs just prior to the time of the event. Source: Proprietary simulationa.
FIG. 3. H2S emissions from the two TGU absorbers after the start of the event. Source: Proprietary simulationa.
What controls treating in TGTUs. The performance of H2S removal in a tail gas treater is almost invariably determined by lean amine acid gas content (i.e., unless the tray count is very low, TGTU absorbers are usually lean-end pinched with respect to H2S). Their performance is controlled by the concentration of acid gases in the lean amine. In this case, however, the absorbers contain only 13 trays each, so there is room for some degree of additional mass transfer rate limitation. Operators and engineers are used to thinking of acid gas content of solvents in terms of acid gases loading (i.e., moles of acid gas per mole of total amine). However, when comparing two amine solutions of differing strengths, acid gas content should be compared based on actual concentration, not on the values of the acid gas loading. Two solutions of a given amine under identical conditions of temperature, pressure and loading but with different strengths do not have the same acid gas (molar) concentrations, and they will not exhibit the same equilibrium partial pressures of the acid gases.
FIG. 4 shows the co-authors’ simulateda profiles of actual and equilibrium H2S partial pressures in Absorber 1 before and after the excursion in solvent strength.
FIG. 4. Simulateda actual and equilibrium H2S partial pressure profiles in Absorber 1 (actual 13-tray count) at 40 wt% amine (left) and 57 wt% amine (right).
In neither case does the performance of the absorber appear to be completely lean-end pinched (i.e., equilibrium limited, because it is easy to imagine that if there were a few more trays, an even lower H2S partial pressure at the absorber outlet could be achieved). This is supported by the plots in FIG. 5 with 17 trays, showing a definite lean-end pinch.
FIG. 5. Simulateda actual and equilibrium H2S partial pressure profiles in Absorber 1 (tray count increased to 18) at 40 wt% amine (left) and 57 wt% amine (right).
The actual 13-tray columns are close to being lean-end pinched, but there is also a degree of mass transfer rate control active throughout the absorbers, partially determining the final treated gas composition.
When controlled by lean amine quality as it is with a lean-end pinch, TGTU performance has more to do with regenerator performance than with the absorbers themselves, although the problem presented here could be resolved by focusing just on the absorbers. TABLE 2 shows that the lean amine H2S concentration is 3.6 times higher in the 57 wt% solvent than in the 40 wt% case, but only a factor of two times higher in terms of loading. It may be of interest to note that CO2 in the lean amine is only minimally affected by the solvent strength. This solvent does a superb job rejecting 97% of the CO2 and absorbing nearly 97% of the H2S from the tail gas.
In this case, the solvent is so highly effective not only in removing the H2S but also at rejecting CO2, that the tiny amount of CO2 co-absorbed is insufficient to affect H2S removal. In tail gas treating with MDEA alone, this is less likely to be the case. Note: When MDEA is the only active ingredient in the solvent, CO2 removal can significantly limit H2S pickup. Absorbed CO2 reduces the amine strength and, more importantly, creates less favorable equilibrium because its own reaction equilibria increase the backpressure of H2S.
Lessons learned. The first takeaway from this study is not to automatically use an amine at the maximum strength allowed by the supplier. Lower strength is sometimes more effective. Solvent strength is an adjustable parameter that can be dialed to provide an advantage.
Two solutions of the same amine at different strengths but with the same acid gas loading have different acid gas concentrations. The actual concentrations determine kinetics and equilibrium, not the acid gas loading. So, care must be taken when comparing different solutions for loading and solvent strength effects. When making up solvent after a purge or to counter vaporization losses, it is easy to overlook the fact that the makeup is probably “neat” solvent and forget to add water-of-dilution. This will result in super high-strength amine that possibly will fail to treat properly.
Absorbers with short, packed beds or only a few trays may not be lean-end pinched in TGTU applications. Even simulated concentration profile plots can be deceptive in this regard. If you are used to TGTUs being lean-end pinched, that rule-of-thumb is valid only usually, not always—another shortcoming of rules-of-thumb.
Higher-strength MDEA solvents are more viscous than dilute ones, which may mean that—contrary to the common rule-of-thumb that high concentrations react faster—CO2 absorption rates may be slower, not faster. Rules-of-thumb should be used critically and cautiously: they sometimes can point in the wrong direction. Nothing is better than a first-rate simulator in providing unequivocal answers.
NOTES
a OGT’s ProTreat V. 8.0
ABOUT THE AUTHORS
Randy Kuroda is a Senior Technical Leader for the GAS/SPEC Technology Group of INEOS. He has been supporting the oil and gas industry working with amines and acid gas removal for more than 25 yr. He holds a BS degree in chemical engineering from the University of California, Berkeley.
Prashanth Chandran leads the software development team at Optimized Gas Treating Inc. He received a B.Tech. degree in chemical engineering from Anna University, India and an MS degree in chemical engineering from Oklahoma State University. During his undergraduate years, he worked as a research intern in Central Leather Research Institute, India, and as a graduate student, he developed novel solvents for desalination and for modeling liquid-liquid equilibria.
Ralph Weiland is a graduate of the University of Toronto with a PhD in chemical engineering. He formed Optimized Gas Treating in 1992 and serves as its Chairman. OGT developed the ProTreat mass transfer rate-base gas treating simulator and the sulfur plant simulator SulphurPro.
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