It was discovered that when the additive concentration increased beyond a certain maximum value, regenerator performance be- came increasingly sensitive to variation in applied steamrate.
This increased sensitivity to energy input is demonstrated conceptually in FIG. 1, which shows trends observed from the
collated plant test data from the TGTUs. FIG. 1 illustrates the
overall relationship between the amount of regeneration-en- hancing additive, energy input and resulting H2S lean loading.
It was observed that, with the same energy input, the solvent becomes leaner when a higher concentration of additive is em- ployed; and, at the same leanness, less steam is required with higher additive concentration.
Case Study 2: Absorber performance. Enhancing regen- eration in an amine unit can benefit treating performance only if the absorber operates at a close approach to lean solvent load- ing. In practice, this means that the absorber must have enough stages to allow for deep treating of H2S. An additional require-
ment is that improvement in regenerator performance must be greater than the loss in the absorber top.
If these requirements are not met, then performance in the absorber can actually worsen when acidic additives are present.
This is because the presence of the additives also results in a higher H2S vapor pressure, which disfavors absorption. The
strength of this impact depends on several interacting factors, such as the relative amounts of H2S, acidic additive and CO2 in
solution, along with the design and operating conditions. In TGTU absorbers, the condition of the top trays is most important for control of absorber performance, and, in this region, coabsorption of CO2 plays a large role. CO2 interferes
in H2S removal, thereby decreasing the effect of enhanced re-
generation. If substantial amounts of CO2 are coabsorbed, then
the approach to H2S equilibrium over the lean solvent worsens,
minimizing the deep H2S treating benefit of the technology.
This effect is illustrated in FIG. 2 from simulation, which is com-
pared against known data;1, 2 partial pressure of H
2S increases
with increasing CO2 coabsorption.
Case Study 3: TGTU with near-flooding conditions. After a major capital change in a TGTU, the amine regenerator began to experience near-flooding conditions, which posed difficulty in achieving deep H2S stripping. In this particular situation, the
operators found that changing the steamrate had only a minor effect on the depth of H2S stripping. When the ambient tem-
perature was high, this unit experienced challenges meeting en- vironmental targets.
A project to address the limitations concluded that the best remedy was to formulate the methyldiethanolamine (MDEA) solvent with the appropriate dosing of proprietary additive. This action succeeded in reducing the regeneration steam by 40% to achieve the desired depth of stripping while the specifi- cation of the treated gas remained unchanged, which also low- ered the regenerator differential pressure and reduced the risk of flooding (FIG. 3).
No change was observed in the decomposition rate of the sol- vent, and no noticeable accumulation of soluble materials was found. Also, following formulation, the operators now observe a clear relationship between the steamrate and the resulting H2S
concentration in the treated gas, improving operability of the unit.3
Case Study 4: Energy savings. Steam savings possible for an example case are illustrated in FIG. 4. Based on the previously
outlined conclusion to target additive content for controllabil-
0.0 0.1 0.2 0.3 0.0 0.2 0.4 0.6 0.8 1.0 H2 S partial pressure CO2 loading 40°C 60°C GPA data, 40°C
FIG. 2. Effect of CO2 coabsorption on H2S absorption.
Relative steam ratio
Relative stripper differential pressure Relative H2S in treated gas, ppmv
0.0 0.0 0.0 0.0 0.0 0.0 0.0 Formulation period 14-Ma y-08 16-Ma y-08 18-Ma y-08 20-Ma y-08 22 -Ma y-08 24-Ma y-08 26-Ma y-08 28-Ma y-08 30-Ma y-08
FIG. 3. Effect of formulation on differential pressure, steamrate and H2S performance.
H2
S in
lean solvent
H2S too sensitive to steamrate
H2S too insensitive to steamrate
Higher additive concentration
Lower additive concentration
Steamrate FIG. 1. Summary of TGTU test data results.
Hydrocarbon Processing | MARCH 2016 41
Corrosion Control
ity, the bulk of the possible steam savings can still be realized, as the steam savings curve flattens at higher acid concentra- tions. In this example case, 40% of the steam can be saved while maintaining improved operability and preserving a minimum concentration of H2S in the lean solvent.
Case Study 5: Application in high-pressure selective treating. Although most of the technology company’s experi- ence is with TGTUs, it has also applied enhanced regeneration in other applications, including selective H2S removal in high-
pressure natural gas. As with the tail gas treating technology, that application requires deeply regenerated lean solvent to meet the H2S specification in the treated gas.
This effect is illustrated in Case 5, in which H2S performance
of the system was optimized by manipulating the extent of re- generation enhancement. FIG. 5 shows the result of changing the
amount of the additive: low H2S lean loadings that occur at high
additive concentrations on an example high-pressure integrated system. This plant was dependent on regeneration enhance- ment to reach targeted H2S concentration in the lean solvent.
Test runs demonstrated that higher levels of enhancement re- sulted in too-deep regeneration—deeper than the company’s technical governance for the application.
Case Study 6: Inferring corrosion effects. It is well known that amine systems processing H2S tend to form a layer of
iron sulfide on exposed carbon steel (CS) surfaces. This layer is thought to help protect CS surfaces against certain types of corrosion. Past publications have introduced the concept that maintaining a minimum level of H2S in the lean solvent facili-
tates preserving this iron sulfide layer.4, 5
This operating philosophy was applied to the plant in Case 5. The depth of regeneration was maintained on target by con- trolling the amount of regeneration enhancement. Monitoring of corrosion coupons, filter changes and solvent-quality tests dem- onstrated a substantial decrease in corrosion in that location.
Building on that success, a systematic review of tail gas treat- ing corrosion experience was conducted in the company’s US downstream applications to document CS corrosion in key lo- cations within the amine units. This review was coupled with solvent quality monitoring in the locations.
The study demonstrated that plants maintaining H2S in the
solvent were less likely to detect iron in solvent quality analysis.
Testing for iron in the solvent samples can give an indication of possible corrosion. Although corrosion may occur without the solubilization of iron, if iron is found in the solvent samples in H2S removal plants, this can be seen as a warning sign of condi-
tions that may lead to corrosion.
Plant data shows that iron content correlates with high acid concentration, as well as low concentration of suppres- sive H2S in the sample. FIG. 6 shows the relationship between
iron content, depth of stripping and additive concentration in the population of TGTUs. A simple relationship is observed: plants that do not strip too deeply are less likely to find iron in solvent samples.
Case Study 7: Regeneration enhancement in CO2-
removal systems. The technology company has also reviewed the effect of regeneration-enhancing additives with the objec- tive of reducing the regeneration heat requirements, both in ad- dition and in comparison to other options to reduce the energy footprint of the unit at a specific plant. Although the CO2 speci-
Steam savings in example case TGTU with AAR
40% of original
Additional steam savings sacrificed for improved operability 16% of original
Required steam ratio Steam savings Acid concentration Ener gy sa vings/ steam r atio
FIG. 4. Steam ratio savings.
Regenerator enhancement
H2
S in lean solv
en
t
Performance target range
FIG. 5. Relationship between H2S lean loading and additive
concentration in a high-pressure application.
Iron not found in solvent samples Iron found in solvent samples Iron occasionally in solvent samples Regeneration enhancement H2 S leanness
42 MARCH 2016 | HydrocarbonProcessing.com
Corrosion Control
fications are somewhat more relaxed, the actual performance examines a similar deep removal compared to the usual H2S
specification partial pressures.
Plant test data in a secondary amine solvent system was tak- en and is presented in FIG. 7, which predicts that, in conditions
similar to TGTUs, steam savings exist for CO2, but are much
lower than for H2S and follow a much flatter curve. With the
lower steam savings, adding acids looks less interesting for CO2
systems—particularly since CO2 is generally easier to strip out
than H2S, and since CO2 specifications are often less severe and
do not require deeper stripping of CO2.
Note that a secondary amine forms carbamates in the pres- ence of CO2, a relatively more stable component, which is more
difficult to regenerate and makes it difficult to strip to very low CO2. FIG. 7 illustrates the effect of the additives. The lines in-
dicate trends derived from plant data, while the performance with additives is shown in data points from the tests. The data indicate that systems using a secondary amine such as DEA or DIPA can also benefit from the addition of acids, but less data are available than for the tertiary MDEA solvents.
Observations have also been made for an MDEA-based sol- vent and are presented in FIG. 8. In this example, a gas treating
unit processing high-pressure gas for deep CO2 removal was an-
alyzed, based on plant performance vs. plant leanness analysis,
in a structured way. The data suggests that the presence of acids in the solvent significantly impacts CO2 lean loading to some
extent. This data presents another example of the effect of acid content in high-pressure absorption, although it is not as pro- nounced as in the case of H2S, for the reasons outlined above.
TAKEAWAY
Enhancing regeneration in amine treating systems has prov- en beneficial in different applications by improving operations and relieving design limitations through reduced steamrates and/or improved treating performance.
However, care must also be taken, since an improper dos- ing of acid can lead to corrosion risk, worse treating perfor- mance and reduced controllability of the unit. From experi- ence in operating with acidic additives and controlled plant tests, several observations were reviewed to understand how to avoid corrosion and improve treating results while applying regeneration enhancement.
NOTE
The tail gas treating technology referenced in this article is Shell Claus Offgas Treating (SCOT) technology, and the proprietary units referenced are Shell SCOT units.
LITERATURE CITED
1 Huang, S. H. and H. J. Ng, “Solubility of H
2S and CO2 in alkanolamines,”
GPA Research Report RR-155, September 1998.
2 Bullin, J. A., R. R. Davison and W. J. Rogers, “The collection of VLE data for
acid gas—alkanolamine systems using Fourier transform infrared spectroscopy,” GPA Research Report RR-165, March 1997.
3 Bonner, S. and J. Critchfield, “Relieving stripper flooding at Martinez SCOT 3,”
presented at Brimstone Sulfur Symposium 2009.
4 Van Roij, J., J. Klinkenbijl, P. Nellen and K. Sourisseau, “Materials threats in aging
amine units,” Paper 2207 presented at NACE Corrosion 2013.
5 API Recommended Practice 945, “Avoiding environmental cracking in amine
units,” April 2008.
DANMI LEE joined the gas processing group at Shell in 2014. Upon completing her master’s degree in chemical engineering at University College London in the UK, she started working for an engineering firm, performing concept studies and preliminary designs for cryogenic gas processing technology. At present, she is working on the development and validation of amine treating models within Shell’s gas processing technology team.
JEANINE KLINKENBIJL joined Shell’s gas treating group in 1982. Her expertise includes absorption, adsorption and sulfur conversion, as well as carbon capture and storage, covering the operation, design and development of new processes, lineups and equipment. Presently, she is team lead in gas processing expertise and also holds the gas treating principal technical expert role at Shell. Some of her previous roles include positions in process modeling, crude characterization, refinery support and IT. She holds a master’s degree in chemical technology from the Technical University in Eindhoven, The Netherlands.
THEO BROK is a senior deployment engineer in the gas processing group at Shell in The Netherlands. He is also a subject matter expert for amine and caustic processes. He is leading the development of the X-solvents (ADIP-X and Sulfinol-X) and has wide experience in sour gas projects. Mr. Brok holds a master’s degree in chemical engineering from the Technical University of Eindhoven in The Netherlands. He has worked for Shell for 27 years, including eight years in LNG and sour gas processing facilities in Brunei and The Netherlands.
JIM CRITCHFIELD is a senior process engineer at Shell Global Solutions in Texas. DIEGO VALENZUELA is a principal process engineer in gas treating and sulfur at Shell Global Solutions in Texas.
H2S AAR DIPA
CO2 AAR DIPA
H2S normal curve
CO2 normal curve
Steamrate
Acid gas lean loading, mol/
mol
FIG. 7. H2S and CO2 lean loading in DIPA before and after adding
additives.
Low acid content Medium acid content High acid content
Steamrate
CO2
leanness, mol/
mol
FIG. 8. Acid impact on CO2 solvent leanness and steamrate on an