a promoter for selective h2s removal.pdf

A promoter for selective H2S

removal: part I

T he selective removal of H2S has become an important topic over past

decades. This is driven by several factors, one being the production of an H2S-enriched, and thus high-quality, Claus gas in MDEA-based acid gas enrichment (AGE) units.

Other fields where selective gas treatment would also be beneficial are natural gas and refinery applications. For sour gas fields, this application is becoming increasingly attrac-tive due to limited sweet gas resources. For refineries, debot-tlenecking issues and an increased flexibility for process-ing different crudes are the most important drivers.

From an operational perspec-tive, savings in energy and circulation rate, as well as a reduction in equipment sizing, are the obvious benefits of enhanced selective treatment. In addition, tight environmental regulations and sulphur specifications are attributed to this subject.

The principles for the selec-tive removal of H2S with amine-based solvents follow three major routes:

A new MDEA promoter achieves very low H2S lean loadings and the option for

flexible design of acid gas enrichment units by varying absorber heights

GErAlD VorbErG, rAlf NoTz and TorSTEN KATz BASF SE WiElAND WAcHE and clAuS ScHuNK Bayernoil Raffineriegesellschaft

• Hindered amines, controlling the selectivity primarily in the absorber• Various design options and absorber internals, affecting the difference in CO2 and H2S mass transfer kinetics • Promoted tertiary amines, focusing more on enhanced regeneration and thus leading to lower H2S loadings.

With respect to the final point, the advanced promoter system presented in this article can be a considerable leap forward for more flexible selec-tive designs. Very low, achievable lean loadings are an option to adjust selectivity by varying the absorber height without losing control over a tight H2S specification with a sufficient safety margin.

This article gives an overview of the principles, while part II (see PTQ, Q2 2011) shows the ability of this promoter system to drop H2S lean loadings in a refinery amine system.

Acid gas removal with amine-based solvents is a mature and widespread appli-cation in the oil and gas industry. Besides specific design variations, acid gas

removal units (AGRU) always follow the principle of an absorber-regenerator configura-tion. First, acid gases are removed from the fluid stream in the absorber by the liquid solvent typically at 20–50°C and elevated pressures up to 80 bar, depending on the feed gas conditions. In a second step, the dissolved acid gases are desorbed in a regenerator at “inverse” conditions. Desorbed acid gases can be further proc-essed in Claus sulphur recovery units (SRU), reinjected for enhanced oil recovery (EOR) or simply flared. When focusing on the two main acid gas components, CO2 and H2S, process designers differentiate between total acid gas removal and selective sulphur removal or simply selective removal. As the name implies, selective sulphur removal selectively removes H2S, while other acid gases, for instance CO2, are slipped into the treated gas.

Consequently, selective removal has a different focus compared with total acid gas removal processes, such as BASF’s aMDEA process, where simultaneous removal of H2S

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and CO2 is intended. This means that suitable solvents have different characteristics.

H2S selectivity

DefinitionsIn industry, various expres-sions for H2S selectivity are used to judge the selectivity of an absorption process with regard to H2S compared to CO2. In the following, the most important examples are given (cH2S and cCO2 stand for molar concentration in gas streams):

• H2S selectivity (rigorous definition)H2S selectivity is calculated as:

• CO2 co-absorption (or CO2 pick-up)CO2 co-absorption in the absorber is specified as:

CO2_co-absorption = 1-

CCO2

treated gas C

CO2 feed gas

• CO2/H2S ratio comparison (often used for acid gas enrichment)The decrease in CO2/H2S ratio indicates the efficiency of an acid gas enrichment unit:

A proper comparison of these expressions for different solvents or applications must be evaluated with great care, since the absolute level of H2S in the treated gas is less consid-ered. In other words, H2S selectivity is well defined, but not particularly suitable for judging H2S specifications in treated gas.

The following example, calcu-lated according to the rigorous definition, might show the difference:

Feed gas: H2S 1 v% CO

2 5 v%

Treated gas case 1: CO2 1.5 v% H

2S 1

vppm → H2S selectivity = 1.428

Treated gas case 2: CO2 1.5 v% H

2S 50

vppm → H2S selectivity = 1.421

Dependency on operatingconditionsSelective treatment with amine-based solvents generally takes advantage of the rapid reaction of H2S compared to the kineti-cally hindered reaction of CO2; CO2 first has to react with water to form carbonic acid. In particular, tertiary amines are often used for selective applica-tions, as they are unable to form carbamates, the only fast reaction involving CO2.

These are the reactions of tertiary amines in aqueous solutions:

reaction of water and amine (fast)R1R2R3N + H

2O ⇔ R1R2R3NH+ + OH

_

2 H2O ⇔ H

3O+ + OH

_

H2S reaction (fast)

H2S + H

2O ⇔ HS

_ + H

3O+

co2 reactions (overall reaction slow):

CO2 + 2H

2O ⇔ HCO

3

_ + H

3O+ (slow)

HCO3

_ + OH

_ ⇔ H

2O + CO

32- (fast)

In this reaction system, CO2 co-absorption, and thus H2S selectivity, is heavily influenced by reaction conditions such as the temperature and concentra-tion of CO2 and H2S in the liquid phase. This means higher pressure and temperature, as well as a higher CO2/H2S ratio in the feed gas, favour CO2 co-absorption and lower H2S selectivity.

ApplicationsSelective H2S removal is predominantly required and applied in the following segments:• Natural gas (NG)• Refinery off-gas (ROG)• Claus tail gas (TG)• AGE.

AGE has probably been the most important driver for the development of selective solvents in recent years. It requires utmost H2S selectivity in order to get a H2S-rich feed gas for the downstream Claus SRU or for down-hole reinjec-tion. For instance, a minimum H2S concentration of 25 vol% is a guiding value for SRUs. Higher H2S concentrations are naturally more desirable.

Upgrading and debottleneck-ing measures triggered the move to more selective treat-ment in refineries by replacing unselective with selective generic solvents. In fact, the majority of refinery expansions lead to a higher total sulphur nameplate capacity by process-ing more sour crudes. Without significant mechanical changes, capacity increases of more than 25% have been achieved, as mainly H2S, instead of CO2 and H2S, has been processed along the entire acid gas removal chain. Moreover, tighter sulphur regulations in many countries have been fulfilled in combina-tion with improved sulphur recovery rates by implementing Claus tail gas treatment (TGT), where H2S is selectively removed and returned to the Claus inlet.

From today’s market perspec-tive, selective acid gas removal in natural gas is an increasingly interesting application. On the one hand, the utilisation of

H2S_selectivity =

(CH2S

feed gas - CH2S

treated gas)/CH2S

feed gas

(CCO2

feed gas - CCO2

treated gas)/CCO2

feed gas

Ratiofeed gas

= C

CO2 feed gas

vs Ratioacid offgas

CCO2

acid offgas

CH2S

feed gas CH2S

acid offgas


more sour gas fields is increas-ing rapidly, while the access to sweet natural gas resources becomes more and more limited (sour in colloquial terms means H2S >5 vol%). On the other hand, for sales gas specification, operators request not the highest level but a dedi-cated or even an adjustable level of selectivity. This means that CO2 slip, and thus H2S selectivity, needs to be control-led to match, for instance, a certain calorific value for the sales gas. CO2 treated gas spec-ifications between 1.5 and 2.5 vol% are most common. But what does this mean for selec-tive designs?

In fact, the quality and quan-tity of production wells change over the years, but the treated gas specification should remain within a narrow window at all times. This task is a challenge for both process design and solvent activity. Proper selec-tive designs should be able to handle: • Various turndown rates• Changing environmental conditions, in particular temperature• Various feed gas scenarios.

Table 1 shows an overview of the application fields and their major differences in conditions and requirements. The listed criteria are crucial for the solvent as well as for design selection.

Solvents for H2S selective

treatmentThree types of solvents are most suitable for selective treatment: generic methyldiethanolamine, MDEA, (tertiary amine) and blends, promoted MDEA and severely sterically hindered amines.


Generic MDEA (tertiary amine) and blendsAmong selective amines, MDEA is the most common due to its many beneficial properties, in particular the inability to enter into the carbamate reaction with CO2. Its ability to change its charac-teristics either for total acid gas removal or selective removal by adding an activator or a promoter has increased its range of application because of: • Availability and pricing• Fewer corrosion issues than with primary and secondary amines• Good absorption performance• Suitability for generic designs• Selectivity adjustment by blending with other amines• Low regeneration demand for absorbed CO2. Promoted MDEAH2S is a stronger acid than CO2 and thus has a stronger bind-ing energy at the stripper temperature. Consequently, amine regeneration of H2S down to trace levels becomes progressively more difficult. In particular, designs with very low H2S specifications in the low ppm range may use regen-eration promoters in order to

release H2S more easily from the solution. In this regard, MDEA acidified with phos-phoric, sulphuric or other acids becomes regenerated more easily. Even the unintentional acidification by formation of heat stable salts (HSS) and their acids — acetates, formates, sulphates and so on — leads to a very efficient H2S regenera-tion boost. However, the level of acidification has a certain limit, as there is an impact on the pH value of the amine solu-tion and the equilibrium curve of the acid gas solubility in the solvent.

Severely sterically hinderedaminesSterically hindered amines, such as tertiarybutylami-noethoxyethanol, incorporate two useful properties at low acid gas partial pressures; as a secondary amine, the reaction is fast and acid gas capture capacity is higher compared to tertiary amines. In contrast to generic secondary amines, steric hindrance due to the shape of the molecule reduces the CO2 equilibrium load and thus increases the selectivity. However, both advantages are progressively reduced at increasing acid gas partial pressures, such as those in

Table 1

Natural gas Acid gas enrichment refinery offgas Tail gasTypical feed gas specificationpH

2S, mbar/psi Up to 10 000/145 Below 500/7.25 Up to 2000/29 Below 100/1.45

pCO2, mbar/psi Up to 10 000/145 Below 2000/29 Up to 1000/14.5 Below 500/7.25

Typical treated gas specification cH

2S, vppm 5–10 5–100 5–100 5–50

CO2 slip Flexible Very high Medium High

System hold-up Large Medium Medium Small

p = partial pressure/c = concentration

characterisation of H2S selective applications


designs, very tight H2S specifi-cations, in the very low ppm range, are required. This means that a design with a large safety margin is highly advisable. As a consequence, process design-ers apply multiple amine feed points to the absorber to adjust the mass transfer area. In some cases, even flexible weir heights are designed as a sophisticated solution. An even higher degree of selectivity through reduction of the tower height could be achieved by reducing the lean loadings and by increasing the driving force for the mass transfer at the absorber overhead.

Mass transfer and internalsselection The pathways of mass transfer for CO2 and H2S are quite different. While CO2 absorption is affected by mass transfer limitations in the liquid phase, the instantaneous H2S reaction in the solvent moves the major H2S mass transfer resistance into the gas phase. As a conse-quence, an adequate design tool has to consider these mass transfer resistances for different components. Rate-based simu-lation tools, which also need detailed input for the column internals, are capable of predict-ing operational conditions with the required accuracy. They can even predict operating condi-tions depending on the flow regime. The results often depend on the choice of inter-nals: trays versus packing.

Trays are very robust and, with respect to multiple amine feed points, the design is easy to implement. In addition, foul-ing or plugging is a minor issue. On the other hand, a packing design usually enables smaller

column diameters to be selected and provides more safety and flexibility for changing L/G ratios. However, the installation of multiple amine feed points is more complex. Lower liquid hold-up and lower back-mixing tendencies increase the selectiv-ity substantially compared to trays operated in their standard envelope.

Temperature and selectivityFeed gas and amine tempera-tures are crucial factors for CO2 co-absorption and resulting selectivity, but the influence from a designer’s perspective is limited to the available cooling capabilities. In regions where seasonal ambient temperatures may differ by more than 40°C (72°F) and peaks may reach 50°C (122°F) or more this is a particular challenge.

By taking the most severe conditions — for instance, high amine and feed gas tempera-tures — as an example, CO2 at a high partial pressure will be absorbed more easily in the amine solution. In addition, the heat of CO2 and H2S absorption expedites the formation of an adverse temperature profile in the absorber (see Figure 1). The continuing acceleration of this phenomenon has a negative influence on overall gas capac-ity and H2S selectivity. Besides the specific heat of absorption and the amount of absorbed CO2 and H2S, further parame-ters, such as the specific heat capacity of gas and liquid phases, heat transfer as well as the L/G ratio, play an impor-tant role. It is obvious that at this point crossover effects between CO2 and H2S start to increase the complexity of the system. It is therefore


most natural gas applications (see Table 1). Thus, for highly selective applications at low H2S partial pressures, such as acid gas enrichment, hindered amines are better positioned and highly efficient. Moreover, the relatively high price level of hindered amines makes it more economical in small plants (AGE) than in large (natural gas) plants.

Design specifics for selective treatmentFor the design, various aspects have to be taken into account:• H2S specification in the treated gas• CO2 specification/slip in the treated gas• Feed gas conditions (composi-tion, pressure and temperature), which may vary over the plant’s lifetime• Required CO2/H2S ratio in the acid off-gas• Ambient conditions• Flexibility/turndown rate• Footprint and size of the plant.

For MDEA-based or other solvents, for which selectivity is controlled by kinetic effects, several factors are important for design: CO2 reaction kinet-ics and number of theoretical stages, mass transfer and inter-nals selection, and temperature and selectivity.

co2 reaction kinetics and

number of theoretical stages With respect to kinetics, shorter absorber columns reduce the overall mass transfer area and overall retention time, so CO2 absorption is reduced to a certain extent. However if the absorber height is too short, H2S may not be absorbed suffi-ciently. In today’s selective



important to understand the temperature profile and location of the temperature bulge, in particular its distance from the very sensitive absorber top, to predict the absorption perform-ance of an operating plant.

Taking these issues into account, design flexibility for selective natural gas plants is driven by:• Variation in absorber height through multiple amine feed points• Low lean amine loading to achieve H2S specification with sufficient safety margin • Flexibility in circulation rate to manage the temperature profile in the absorber and control CO2 mass transfer • Sufficient reboiler energy to keep the lean loading low at various circulation rates.

Promoted MDEA solvent for natural gas plantsMost natural gas plants have CO2 partial pressures >1.5 bara (>21.8 psi). At these conditions, MDEA-based solvents are closer to hindered amines from a selectivity perspective. In addi-tion, the relatively high total acid gas partial pressures of natural gas plants reduce the acid gas capacity advantage of hindered amines. Moreover, temperature profile and bulge control at high ambient temper-atures often determine the circulation rates of many AGE units and result in relatively low acid gas loadings in the amine solution in the absorber bottom. The required over-circulation may become even worse for hindered amine designs, since the advantage of higher acid gas absorption capacity is partly compensated by the lower heat capacity of a


smaller solvent flow rate. Temperature bulge effects in hindered amines are compara-tively more sensitive regarding the absorption performance. In some cases, additional side cool-ers may help to increase the performance of these processes. Last but not least, the size of today’s natural gas trains, with an amine hold-up of several hundred tonnes, makes the use of MDEA-based solvents much more economical.

Promoted MDEA solvent forrefineriesThe AGRU setup of a refinery is very complex and the differ-ent requirements of the absorbers prefer an all-fits-one solution. Although acid gas partial pressures are different from those of natural gas plants, MDEA-based solvents are well established and are represented today in more than 40% of all refinery amine systems. In addition, the rela-tively high refill demand comes along with pricing and availability. With respect to regeneration energy, the

unintentional and sometimes quick formation of HSS to concentrations of up to 3 wt% is supportive to some extent. However, corrosion issues force refiners to neutralise those acids with caustic solution.

New-generation promoter systemA new promoter has been developed and incorporated: BASF’s selective sMDEA+ technology. This promoter formulation is highly efficient in achieving very low H2S lean loadings. In this respect, the promoter formulation provides an option to design selective units with a high degree of flex-ibility by varying absorber heights, while low acid gas lean loadings keep H2S outlet concentrations at a very low level.

The following describes the mechanism of achieving low acid gas lean loadings.

PrinciplesDesorption mechanism in the stripperH2S desorption follows an

30

50

45

40

35

25

20

15

10

5

40 45 50 55 60 65 70 75 80 85

Ab

sorb

er

heig

ht,

segm

en

tsTemperature, °C

0

figure 1 Absorber, liquid-phase temperature profiles — red: feasible T-profile at appropriate L/G ratio; blue: T-bulge profile at too low L/G ratio



equilibrium reaction between amine, protonated amine and the dissolved HS_ anion, described in the following reaction:

H2S + MDEA ⇔ HS- + MDEAH+

CO2 desorption can be described by the following net equilibrium reaction:

CO2 + MDEA + H

2O ⇔ HCO

3

- +

MDEAH+

The purpose of desorption is to strip H2S and CO2 from the rich solution to obtain a regen-erated solvent. As a consequence of CO2 and H2S mass transfer from the liquid phase into the gas phase, the above two equilibrium reac-tions move towards the left side and the pH value of the solution increases accordingly from the top to the bottom of the stripper.

Since CO2 is a weaker acid at typical stripper temperatures compared with H2S, CO2 is preferably released in the upper part of the stripper, whereas a significant amount of H2S — as the stronger acid — is released

in the lower part of the strip-per. Releasing CO2 and obtaining low residual CO2 concentrations becomes easier than achieving low H2S resid-ual loading, which requires much more stripping stream and reboiler energy.

Low acid gas concentrations in the lean solvent are directly linked to the maximum achiev-able gas purities in the absorber overhead: unfortunately, most gases have very tight H2S spec-ifications — for instance, 5–10 vppm for natural gas; see Table 1 — but much looser CO2 speci-fications. However, this requirement is in opposition to the chemistry of H2S desorp-tion, described above.

Another effect that hampers H2S desorption is related to the pH value increasing steadily towards the stripper sump. As a consequence, the ratio between protonated HS- and H2S increases according to the well-known correlation between the pH value and pKa values of an acid/base system:

log f[HS-]

p = pH - pK

aH2S

[H2S]


Considering these issues, it becomes obvious how energy intensive the purification of gases down to very low H2S ppm levels can be when amine-based solvents are used. In this respect, the addition of an acid to amine solvents has become a common solution to overcome the effect of high pH value and to detain acid/base reactions in the stripper sump.

In other words, a further decrease in H2S loading can be obtained by shifting the equi-librium of the reaction

H2S + MDEA ⇔ HS

_ + MDEAH+

towards the H2S side, by adding a strong acid (AH) to the system:

HS_ + AH ⇔ H

2S + A

-

However, a decrease in the pH value in the stripper and an increase in the protonated amine concentration also affect the absorber pH value (see Figure 2) and thus the equilib-rium loading. Consequently, acidification is limited to some extent, so acidified MDEA

6

5

4

3

2

1

7.5 8.0 8.5 9.0 9.5 10.0 10.5 11.0 11.5 Bottom

pH

Absorber

0

Acidified MDEAMDEA

High acid gas concentration

10

8

9

4

5

6

7

3

2

1

7.5 8.0 8.5 9.0 9.5

pH

Desorber

0

Acidified MDEA

MDEA

Low acid gas concentration

Top

figure 2 Example of pH profiles in an absorber (left) and a desorber (right) with generic MDEA and acidified MDEA


6 GAS 2011 www.digitalrefining.com/article/1000410 www.digitalrefining.com/article/1000410 GAS 2011 7

solvents may require an increase in liquid flow rate to cope with this negative side effect. This is a crucial point, especially at elevated amine and feed gas temperatures above 40°C (104°F).

The respective isothermal equilibrium curves demonstrate that an ideal promoter system needs to have an acidic charac-ter in the stripper bottom, but a neutral impact in the absorber overhead (see Figure 3). In addition, no negative side effects, such as foaming, corro-sion, thermal instability or even evaporation, should occur. Such a tailor-made solvent — which at least comes close to the ideal solvent — has been developed and is described next.

regeneration test runs and achievable absorberspecificationsFigure 4 shows the graph of a regeneration lab test run with MDEA, acidified MDEA (H3PO4) and MDEA with the new promoter system

15

25

20

10

5

H2S

lean loadin

g,

Nm

3/t

o

Regeneration energy0

0.18

0.30

0.24

0.12

0.06

H2S

lean loadin

g,

Nm

3/t

o

0.00

Acidified MDEAsMDEA™+

MDEA

0.3

0.5

0.4

0.2

0.1

H2S

lean

load

ing,

Nm

3/t

o

Regeneration energy0.0

0.0036

0.0060

0.0048

0.0024

0.0012

H2S

lean

load

ing,

mol/

mol

0.0000

figure 4 H2S regeneration lab tests (reduced desorber height)

(sMDEA+ technology), with the residual H2S lean loading (Nm3/t, mol/mol) against regeneration energy, Q. In the important regime of very low loadings (<0.5 Nm3/t, <6E-3 mol/mol), a magnified graph illustrates the difference.

Figure 5 illustrates the corre-sponding H2S concentration profile in the gas phase for a 10m packed-bed absorber with

H2S

part

ial pre

ssure

H2S loading

MDEA + promoterPromoted MDEA

MDEA

Strippersump

Absorberhead

50ºC

120ºC

figure 3 Influence of the acidic promoter formulation on the isothermal equilibrium curves at 50°C and 120°C (H2S

partial pressure regime of 1 mbar)

a feed gas partial pressure for CO2 of ~2 bar (29 psi) and H2S ~1 bar (14.5 psi) at 40°C (104°F). As a matter of equilibrium, the respective H2S specification for MDEA is in the low hundreds ppmv range, while for acidified MDEA the H2S specification would be around a tenth of this. In the sMDEA+ case, the ultra-low lean loading in the 1E-4 mol/mol range is able to

figure 2 Example of pH profiles in an absorber (left) and a desorber (right) with generic MDEA and acidified MDEA



achieve a treated gas specifica-tion below 5 ppmv, with sufficient safety margin and a negligible impact on the H2S absorption capacity at the absorber bottom.

To reach a similar low lean loading with a state-of-the-art acidified MDEA, a doubling of the H3PO4 concentration would be required. But, as a conse-quence of this measure, the absorber equilibrium curve and thus the entire acid gas capac-ity would suffer, requiring a compensation of approximately 5–12% higher amine liquid load.

conclusionsBesides highly selective AGE applications, H2S selective acid gas removal has become an increasingly important field for world-scale natural gas plant designs. Contrary to acid gas enrichment techniques, selec-tivity and thus CO2 slip are limited and require some adjustability and flexibility.

From a solvent technology perspective, advanced H2S selective acid gas removal can

be carried out through steri-cally hindered amines or tertiary amines, both in combi-nation with other amines or a promoter system. Additionally, sophisticated design measures are applied to ensure a reliable operation.

Today’s plants require a very high degree of flexibility in turndown rates, changing feed gas specifications and condi-tions. In addition, very tightly treated gas sulphur specifica-tions in the low ppm range (<5 ppmv) are mandatory.

The high acid gas partial pressures in most natural gas applications, and the require-ment for adjustable selectivity, make MDEA-based technolo-gies attractive due to competitive solvent prices and generic designs. For opex, capex and specification purposes, acidic promoted systems are in use to overcome the relatively high H2S binding energy and to lower residual H2S loading in the amine.

However, current acidified state-of-the-art systems also have their limits, as the

improved regeneration will trigger an inverse effect on the entire capacity. Alternatively, the new, proprietary promoter system described in this article shows different behaviour: a substantial increase in regener-ation ability while hardly affecting absorption capacity.

further reading1 Bullin J A, Polasek J, Selective absorption using amines, 61st GPA Conference, Tulsa, Oklahoma, 1982. 2 Harbison J L, Handwerk G E, Selective removal of H

2S utilizing generic MDEA, 37th

Annual Laurance Reid Gas Conditioning Conference, Norman, Oklahoma, 1987. 3 Carey T R, Hermes J E, Rochelle G T, A model of acid gas absorption/stripping using methyldiethanolamine with added acid, Gas Separation & Purification, Jun 1991, vol 5.4 Kohl A L., Nielsen, Gas Purification, 5th ed, Gulf Publishing Corp, 1997.5 Weiland R H, Dingman J C, Effect of solvent blend formulation on selectivity in gas treating, 45th Annual Laurance Reid Gas Conditioning Conference, Norman, Oklahoma, 1995.6 Huffmaster M A, Stripping requirements for selective treating with Sulphinol and amine systems, 47th Annual Laurance Reid Gas Conditioning Conference , Norman, Oklahoma, 1997.7 Weiland R H, Sivasubramanian M S, Dingman J C, Effective amine technology: controlling selectivity, increasing slip, and reducing sulphur, 53th Annual Laurance Reid Gas Conditioning Conference, Norman, Oklahoma, 2003.8 A Refinery for Bavaria, official Bayernoil brochure, July 2009.

Gerald Vorberg is a Senior Technology Manager in BASF’s Gas Treatment team in Ludwigshafen and Project Leader for Selective Acid Gas Removal. He joined BASF’s Catalyst Group in 1997 as a Global Product Technology Manager and holds a diploma in chemical engineering from the University of Applied Sciences (FHT), Mannheim, Germany. Email: [email protected] Notz is a Research Engineer at BASF SE in Ludwigshafen. He holds a


m,t

hgi

eh

re

bros

bA

H2S concentration, mol%

figure 5 Absorber H2S profile [0]



diploma in process engineering from the University of Stuttgart and a PhD in CO

2 capture from power plant flue gas

by reactive absorption from the Institute of Thermodynamics and Thermal Process Engineering at the University of Stuttgart. Email: [email protected] Katz is head of the Global Technology Team at BASF SE and coordinates BASF’s new business development activities in gas treatment. He studied mechanical engineering at the Technical University of Aachen, Germany (RWTH Aachen) and holds a PhD in

evaporation technology. Email: [email protected] Wache is a Process Engineer at Bayernoil Refinery in Vohburg, Germany. He holds a diploma in chemistry from the Technical University (RWTH) Aachen and a PhD in chemical engineering on Fischer-Tropsch synthesis and dehydrogenation of middle distillates from the University of Bayreuth. Email: [email protected] Schunk is Plant Manager at Bayernoil Refinery in Vohburg and was formerly Lead Process Engineer for the

development and implementation of the OATS units. He holds a diploma in process engineering from the Technical University Karlsruhe. Email: [email protected]


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