AMINE DEGRADATION and ASSOCIATED PROBLEMS in the GAS TREATING UNIT E.R.Baumeister1 , R.C.O.Souza2

IBP2323_08

AMINE DEGRADATION AND ASSOCIATED PROBLEMS IN THE GAS TREATING UNIT E.R.Baumeister1 , R.C.O.Souza2

Copyright 2008, Instituto Brasileiro de Petróleo, Gás e Biocombustíveis - IBP Este Trabalho Técnico foi preparado para apresentação na Rio Oil & Gas Expo and Conference 2008, realizada no período de 15 a 18 de setembro de 2008, no Rio de Janeiro. Este Trabalho Técnico foi selecionado para apresentação pelo Comitê Técnico do evento, seguindo as informações contidas na sinopse submetida pelo(s) autor(es). O conteúdo do Trabalho Técnico, como apresentado, não foi revisado pelo IBP. Os organizadores não irão traduzir ou corrigir os textos recebidos. O material conforme, apresentado, não necessariamente reflete as opiniões do Instituto Brasileiro de Petróleo, Gás e Biocombustíveis, seus Associados e Representantes. É de conhecimento e aprovação do(s) autor(es) que este Trabalho Técnico seja publicado nos Anais da Rio Oil & Gas Expo and Conference 2008.

Resumo

A degradação das aminas e os problemas relacionados em uma unidade de tratamento de gás, não podem ser evitados ou eliminados completamente, entretando, podem ter seus custos eficazmente atenuados usando um programa profundo de gerenciamento da unidade. Os benefícios econômicos e de desempenho, a partir de um programa de gerenciamento da amina, incluem diversas melhorias e índice de desempenho. Melhoria de desempenho, custos operativos mais baixos, e baixo impacto ambiental são algumas das vantagens adicionais de se usar um sistema de gerenciamento detalhado de uma unidade de tratamento de gás.

Summary

Amine degradation and associated problems in the amine gas treating unit cannot be completely avoided or eliminated. They can be cost effectively mitigated using a thorough amine management program. Economic and performance benefits realized from an amine management program include several improvements and performance index. Better yields, lower costs, and fewer environmental concerns are some of the additional advantages of using a comprehensive amine management system to help run the amine gas treating unit.

Abstract

Amine based gas treating systems can have problems with solvent degradation for many reasons including operating conditions that permit inlet contaminants. This degradation can lead to frequent troubleshooting of the amine system. One important consequence of degradation is the formation of Heat Stable Amine Salts (HSAS). We define HSAS as the amount of amine cation required to neutralize acids not regenerated under normal regenerator conditions. Heat stable salts in amine solutions, as amine or stronger base salts, can cause a number of operational problems.

All of these problems have been experienced in numerous applications of amine treating.

______1 Ph.D. in Organic Chemistry; Senior Technical Service Specialist – Dow Chemical Co. 2 Chemistry Bachelor; Senior Oil &Gas Development Specialist – Dow Brasil S/A Rio Oil & Gas Expo and Conference 2008

• Corrosion and erosion of metal components are accelerated by the precipitation of salts or corrosion end products. • Foaming may be caused by changes in the surface active character and the increased viscosity of the solution. • Reduced acid gas carrying capacity is the result of less amine present in a usable absorptive state.

Reduction or removal of heat stable salts ultimately requires reclaiming the amine solution by electrodialysis, vacuum distillation, ion exchange resin treating, dilution through purge and make up or total solvent replacement. The challenge lies in identifying the acceptable operating limits of heat stable salts and preventing the escalation of these problems. It is apparent that a number of factors must be included in determining those limits. Heat stable amine salts are formed with acidic components other than H2S and CO2 in the inlet process stream to the amine absorber. Typical acidic components include acids that form salts of chloride, sulfate, formate, acetate, oxalate, cyanide, thiocyanide, and thiosulfate. In addition, oxygen absorbed into the amine solution creates amine oxidation products that include formate, acetate, and glycolate.

Many factors must be considered when determining a reasonable limit of heat stable salts in amine solutions. These can be broadly categorized as one of the following: • The character of the heat stable salt species. • The operating conditions of the amine unit. • The mechanical design of the amine unit.

The term "heat stable" is a broad term used to describe a number of undesirable salts in an amine solution. They are undesirable because they cannot be effectively removed in the normal pressure/temperature swing in the absorption and desorption cycle of gas treating within amines units. In actuality, the stability of these salts depends on the species of the anion and cation which makes up the salt.

In this paper we will cover common aspects involved with amine degradation, explaining the reason they occur, the different degradation for each amine used for acid gas removal, the consequences in the system and how to control them thru an Amine Management System, based on a low total cost approach to treat HSAS, reduce contamination, and minimize corrosion.

1. Introduction

Amine solvent formulations are used to remove acidic components such as CO2 and H2S from gas streams to comply with sales gas specifications for end use or to make the gas suitable for liquefaction.

During operation of an amine unit, degradation of the solvent occurs due to reaction with contaminants like oxygen, sulfur dioxide, and acids or acid precursors in the feed gas. Some of the tertiary amine oxidation products include secondary amines. These degradation products lead to a number of operational problems in the amine units if allowed to build up in concentration. Build up over time is related to solvent age, use and handling and will occur in every amine solvent.

Common Operational Problems include: 1. Increased corrosion rates, particularly at the lean side of the amine unit. 2. Fouling in those parts of the unit where solvent flow velocities are low and the solvent loading of H2S or CO2 is high, i.e. the trays and the bottom of the contactor and the lean/rich heat exchanger. In “CO2-only” systems,

2 Rio Oil & Gas Expo and Conference 2008 fouling tends to occur more often in the regenerator overhead. Fouling of the heat exchanger leads to a reduction in heat transfer and an increased steam use for regeneration. Ultimately, plugging of the heat exchanger may occur, restricting solvent circulation and treating capacity. 3. Decreased treating capacity of the unit due to lower amount of active amine available for acid gas removal. 4. Increased foaming tendency of the solvent from higher levels of suspended solids (also requiring a higher rate of filter change outs). 5. A high flash gas production due to a high carry-under of gas with solvent in the main absorber. 6. Decreased CO2 slip due to the presence of secondary amines.

One of the oxidation products, bicine, does present problems in H2S removal applications where all of the H2S is removed from the amine solution. In the regenerator, the bicine-iron complex is decomposed in the presence of H2S. The overall result is a high activity of the “iron pump” mechanism leading to high corrosion rates and associated fouling problems. Careful monitoring of the operation of the unit in combination with measuring solvent composition and solvent properties, combined with good solvent maintenance practices will ensure reliable operation of the amine unit.

2. Amine Treatment Unit

Amine treatment units are typically employed for the removal of acid components from natural gas. Depending on the concentration of CO2 and H2S in the gas, the required specification of the treated gas and the required selectivity of the removal of H2S over CO2, an appropriate alkanolamine formulation are chosen.

Due to an increased environmental awareness and stricter operational disciplines, many gas-treating plants have reduced solvent losses and the subsequent make up with fresh amine. This has resulted in build up of amine degradation products becoming an important issue. A solvent quality monitoring service can be used to measure the amine composition of the solvent and to determine the presence of acid components and heavy amine degradation products.

Because the amine unit uses an aqueous solution of the amine, absorption of hydrocarbons, mercaptans and organic sulfur species from gas streams is minimal. MDEA is normally chosen when a high selectivity for H2S absorption relative to CO2 is of paramount importance. Other amines used in refinery applications are DEA (di- ethanolamine), MEA (monoethanolamine), DGA (di-glycolamine), sterically hindered amines and various specialty amines which are proprietary mixtures of amines and additives to improve selectivity, kinetics and stability.

3. Amine Contaminants and Degradation

3.1. Contaminants Amine contaminants can be grouped into four distinct categories; (1) heat stable salt anions, (2) injection chemicals, (3) hydrocarbons and (4) particulates. All of these contaminants categories are typically present in any given amine system at the same time, although the amount of each one can vary from insignificant to several percent.

1) Heat Stable Salts: Acid anions such as formate, acetate, thiosulfate, thiocyanate, and chloride can tie up an amine molecule to form a salt that is not capable of being regenerated by the addition of heat, and are thus referred to as Heat Stable Salts. Not only do they tie up the amine and thereby reduce the acid gas carrying capacity, but at higher concentrations they may also be corrosive.

2) Injection Chemicals:

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Corrosion inhibitors from upstream pipeline operations and amine system injections, such as anti-foam chemicals can concentrate in amine systems. While these chemicals are excellent in controlling other operational problems, their injection into an amine system over months or years can build up to a substantial percentage of the amine composition concentration. A large buildup of injection chemicals can eventually lead to fouling and can cause changes in solution physical properties, such as viscosity and mass transfer.

3) Hydrocarbons: Heavy hydrocarbons from natural gas streams can condense in the contactor and lubrication oil from upstream reciprocating compression can build up in amine systems over time. These hydrocarbons can cause foaming, and at high enough concentrations, can change amine solvent physical properties.

4) Particulates: Typical insoluble particulates include iron sulfides, metals from equipment corrosion, charcoal fines from amine filters, and catalyst fines from upstream units.

Amine manufacturers and suppliers stress overall solvent quality. When thinking about overall amine hygiene, it should be kept in mind that any compounds in an amine system that are not either (1) amine or (2) water are considered contaminants and should be removed when they exceed recommended levels.

3.2. Degradation

Effect of Heat Stable Salts Carbon dioxide and hydrogen sulfide are weak enough acids that their reactions with amines are thermally reversible. Acids which are sufficiently strong so that their reactions with amines are not thermally reversible are called heat-stable salt forming acids. That is, products of their acid-base reactions with amines form heat stable salts. If heat- stable acids enter an amine unit or are generated there by reaction with trace amounts of an oxidizer (oxygen or SO2), or by thermal degradation of the amine, the heat-stable salts will remain in solution and accumulate.

Heat-stable salts have several sources. In refineries, FCCU gases may contain trace amounts of formic and acetic acids. Traces of oxygen in various refinery gas streams (FCCU, Delayed Coker, Vacuum Unit, Vapor Recovery System), air leaking into gas gathering systems operating under vacuum, and oxygen in un-blanketed amine storage tanks and sumps can react with the amine to form low molecular weight carboxylic acids and react with H2S to form elemental sulfur and thiosulfate. If HCN is present in the feed gas, elemental sulfur in the amine solution reacts with cyanide to form thiocyanate.

Heat-stable salts reduce the acid gas removal capacity of the amine solution because they react irreversibly with the amine under normal amine unit operating conditions. Additional amine is required to maintain targeted solution strength levels for acid gas removal. Amine solutions can also be corrosive if they are contaminated with heat- stable salts. Heat-stable salts are corrosive because they facilitate the corrosion reactions and may also act as chelating agents, dissolving non-sulfide protective films covering the base metal. It is also possible that low levels of some of the weaker heat-stable acids, such as formic acid, are present under regenerator conditions which will react with exposed carbon steel surfaces that condense water vapor.

Effect of Amine Type on Amine Solution Corrosion It is well known that the choice of amine affects corrosion. Primary amines like MEA and DGA are more corrosive than secondary amines like DEA and DIPA. In turn, DIPA and DEA are more corrosive than tertiary amines like MDEA. Exactly why this is true is not fully understood. Several investigators have shown that all amines are equally non-corrosive when no acid gas is present.

In the presence of H2S and O2 in the gas, a range of reactions may occur leading to the formation of thiosulfate, sulfur, polysulfides and sulfate.

One of the first markers of oxygen ingress in the solvent, in the presence of H2S, is the formation of thiosulfate. Part of the thiosulfate will be oxidized further to give sulfate. If oxygen ingress is only periodic or if it is the result of a single operational event, then this will be evidenced by a sudden increase of the thiosulfate content of the solvent, followed by a steady decrease to steady state concentration.

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Reaction with oxygen The presence of oxygen in the feed gas to the amine unit may lead to degradation of the amine solvent. In lab experiments, several mechanisms have been identified, depending on the composition of the gas. Oxygen can react directly with the amine or alternatively, if H2S is present in the feed, oxygen can react with a sulfur species first, followed by a subsequent reaction with the amine.

The product distribution of the various carboxylic acids depends on the oxygen concentration, the operating temperature and the amine type used. Under conditions of high temperature and high oxygen concentration the product distribution for the organic acids shows that oxidation is not very selective and splitting of the αN-CH2 bond occurs together with the further decomposition of the acid formed. Alternatively, C-C bond fission occur leading to the formation of acetic acid and formic acid.

In the presence of oxygen at high temperatures the formation of hydroxyl radicals may occur. These hydroxyl radicals will abstract a α-hydrogen atom next to the nitrogen to give the corresponding radical. This radical can react with oxygen to give the peroxy radical that abstracts another hydrogen atom from the primary amine, thereby completing the cycle.

4. Solving Problems

4.1. Methods of handling contaminated amine systems There are several methods depending on the type of contaminants. One or more of the following methods can be used for cleaning an amine system: • Disposal and Replace • Continuous Disposal and Replace (Bleed & Feed) • Filtration of Particulates • Neutralization of Heat Stable Salts • Electrodialysis • Ion exchange • Vacuum Distillation Reclaiming.

Until recently, both Dispose/Replace, and Bleed/Feed were commonly used for controlling contaminants. However, increased cost of amines and disposal have made these methods less economical. These methods of purification should now only be considered as a last resort.

Particulate filtration is the preferred method if suspended solids are the only contaminant. Carbon filtration can be used to control hydrocarbons and injection chemicals. When carbon filtration is used, particulate filtration is recommended both before and after the carbon bed.

Heat Stable Salts should be controlled by neutralization to not more than 2 wt% as the amine in use. This minimizes the amount of non-productive amine in the solution. The use of neutralization allows additional operating time before reclaiming needs to be done. Salts produced by addition of a strong base neutralizer can be removed by electrodialysis, ion exchange or vacuum reclamation.

4.2. Unit Management Amine based gas treating systems can have problems with Heat Stable Amine Salts (HSAS). HSAS cause corrosion, reduced amine capacity, facilitate poor unit operations, reduced solvent life and solvent disposal problems.

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Some companies have developed programs those minimize the problems associated with HSAS, maximize solvent life, and restores operational reliability. Dow’s Heat Stable Salt Management Program is based on a low total cost approach to treat HSAS, reduce HSAS contamination, and minimize the corrosion from HSAS.

Benefits of Heat Stable Salt Management • Reduce corrosion and equipment replacement costs • Reduce or eliminate solvent disposal and associated environmental costs • Optimize amine system capacity for acid gases and avoid unit shutdowns • Minimize maintenance costs due to system cleanings and frequent filter change outs • Avoid high energy and amine solvent consumption

Heat Stable Salt Management Program Elements Monitoring and Prediction: Solvent analyses determine the HSAS profile and predict when remedial action is necessary.

Control Strategies: System configuration is studied to determine if operations can be adjusted to reduce the formation of contaminants or to achieve more effective removal of contaminants upstream of the amine system.

Neutralization Technology: The resulting neutralized salt is substantially less corrosive than the amine salt. Therefore, the solvent can tolerate a higher level of HSAS forming anions, and amine solution life is extended significantly, if not indefinitely. Ucarsol* DHM* Neutralizer has been developed to easily and effectively neutralize HSAS.

Removal: The system might eventually require some type of solvent purification, especially if solvent losses are low. Purging the solvent to remove HSAS loses valuable amine and is no longer economically or environmentally justifiable. The patented UCARSEP* Amine Reclamation System is used for on site and on line salt removal. This process has been used to clean up formulated amines, MDEA, and DEA solvents without interruption of amine system operations.

5. Conclusions

• Increased reliability with reduced operating and maintenance costs • Increased throughput—the system performs economically at the optimum operating concentration • Lowest cost reclaiming technology without operating interruptions • Reduced amine disposal, emission and environmental costs • Reduced solvent losses, costs and contamination of downstream processes • Reduced corrosion-related costs and downtime • Improved understanding of unit operations by operating personnel • Improved operation of downstream units

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Better yields, lower costs, and fewer environmental concerns are some of the additional advantages of using a comprehensive amine management system to help run the amine gas treating unit.

6. Acknowledgement

"The authors wish to express their sincere appreciation to Dr. Sid Bosen for his significant contribution and technical review of the paper."

7. References

1. R. Haws -CCR Technologies Inc.; Paper: Contaminants in Amine Gas Treating 2001GPA Houston Regional Meeting

2. R. B. Nielsen, K R. Lewis - Fluor Daniel, Inc.; John G. McCullough - Proton Technology, Ltd.; D. A. Hansen - Fluor Daniel, Inc. – Paper: Controlling Corrosion in Amine Treating Plants

3. H.J. Liu and J.W. Dean - Union Carbide Corporation; Sidney F. Bosen - Union Carbide Corporation Technical Paper Number 572 Presented at: NACE International, Corrosion/95 - Neutralization Technology to Reduce Corrosion from Heat Stable Amine Salts

4. The Dow Chemical Company, Midland, Michigan 48674 U.S.A. “Amine Management Program – Heat Stable Amine Salts Maintenance Guidelines”

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