Amine unit corrosion in refineries EFC46 (European Federation of Corrosion)

Amine unit corrosion in refineries

i

ii

European Federation of Corrosion Publications NUMBER 46

Amine unit corrosion in refineries J. D. Harston and F. Ropital

Published for the European Federation of Corrosion by Woodhead Publishing and Maney Publishing on behalf of The Institute of Materials, Minerals & Mining

CRC Press Boca Raton Boston New York Washington, DC

WOODHEAD

PUBLISHING LIMITED

Cambridge England iii

Woodhead Publishing Limited and Maney Publishing Limited on behalf of The Institute of Materials, Minerals & Mining Published by Woodhead Publishing Limited, Abington Hall, Abington, Cambridge CB21 6AH, England www.woodheadpublishing.com Published in North America by CRC Press LLC, 6000 Broken Sound Parkway, NW, Suite 300, Boca Raton, FL 33487, USA First published 2007 by Woodhead Publishing Limited and CRC Press LLC © 2007, Institute of Materials, Minerals & Mining The authors have asserted their moral rights. This book contains information obtained from authentic and highly regarded sources. Reprinted material is quoted with permission, and sources are indicated. Reasonable efforts have been made to publish reliable data and information, but the authors and the publishers cannot assume responsibility for the validity of all materials. Neither the authors nor the publishers, nor anyone else associated with this publication, shall be liable for any loss, damage or liability directly or indirectly caused or alleged to be caused by this book. Neither this book nor any part may be reproduced or transmitted in any form or by any means, electronic or mechanical, including photocopying, microfilming and recording, or by any information storage or retrieval system, without permission in writing from the Woodhead Publishing Limited. The consent of Woodhead Publishing Limited does not extend to copying for general distribution, for promotion, for creating new works, or for resale. Specific permission must be obtained in writing from Woodhead Publishing Limited for such copying. Trademark notice: Product or corporate names may be trademarks or registered trademarks, and are used only for identification and explanation, without intent to infringe. British Library Cataloguing in Publication Data A catalogue record for this book is available from the British Library. Library of Congress Cataloging in Publication Data A catalog record for this book is available from the Library of Congress. Woodhead Publishing ISBN-13: 978-1-84569-237-7 (book) Woodhead Publishing ISBN-13: 978-1-84569-323-7 (e-book) CRC Press ISBN-13: 978-1-4200-5495-8 CRC Press order number: WP5495 ISSN 1354-5116 The publishers’ policy is to use permanent paper from mills that operate a sustainable forestry policy, and which has been manufactured from pulp which is processed using acid-free and elementary chlorine-free practices. Furthermore, the publishers ensure that the text paper and cover board used have met acceptable environmental accreditation standards. Typeset by Replika Press Pvt Ltd, India Printed by T J International Limited, Padstow, Cornwall, England

iv

Contents

Series introduction

ix

Volumes in the EFC series

xi

1

Introduction

1

2

Technical background

3

2.1

Process issues 2.1.1 Pretreatment 2.1.2 Absorber 2.1.3 Regenerator Important issues Corrosion issues 2.3.1 General factors 2.3.2 Mechanisms 2.3.3 Rich amine 2.3.4 Lean amine 2.3.5 Acid gas attack 2.3.6 Heat-stable amine salts 2.3.7 Make-up water quality 2.3.8 Erosion corrosion 2.3.9 Proprietary chemical additions 2.3.10 Corrosion in regenerator overheads 2.3.11 Hydrogen-related cracking in wet H2S systems 2.3.12 Alkaline stress corrosion cracking Materials

3 3 3 3 4 4 4 4 5 5 5 5 5 6 6 6 6 6 7

Experiences of ten plants using methyldiethanolamine

9

3.1 3.2

9 9

2.2 2.3

2.4 3

Gas composition Materials of construction

v

vi

Contents

3.3

3.4

3.5 3.6 4

3.2.1 Carbon steels 3.2.2 Special carbon steels 3.2.3 Special stainless steels 3.2.4 Overlays, cladding and coating 3.2.5 Stress-relieving policy Operating parameters 3.3.1 Amine parameters and foaming 3.3.2 Acid gases, heat-stable amine salts, velocities and reboiler temperatures 3.3.3 Make-up water 3.3.4 Solids present and filtration 3.3.5 O2 leakage 3.3.6 Inlet gas knock-out vessel 3.3.7 Design factors Corrosion control 3.4.1 Treatments 3.4.2 Monitoring 3.4.3 Control parameters Corrosion problems experienced Summary of selected data

9 10 10 10 11 11 11 12 13 13 13 13 14 14 14 14 15 15 17

Experiences of twenty-one plants using diethanolamine

19

4.1 4.2

19 20 20 20 20 21 22 22 22

4.3

4.4

Gas composition Materials of construction 4.2.1 Carbon steels 4.2.2 Special carbon steels 4.2.3 Special stainless steels 4.2.4 Overlays, cladding and coating 4.2.5 Stress-relieving policy Operating parameters 4.3.1 Amine parameters and foaming 4.3.2 Acid gases, heat-stable amine salts, velocities and reboiler temperatures 4.3.3 Make-up water 4.3.4 Solids present and filtration 4.3.5 O2 leakage 4.3.6 Inlet gas knock-out vessel 4.3.7 Design factors Corrosion control 4.4.1 Treatments 4.4.2 Monitoring 4.4.3 Control parameters

23 24 24 25 25 26 26 26 26 27

Contents

4.5

5

Corrosion problems experienced 4.5.1 Findings for each plant 4.5.2 Location of problems per item of equipment

27 27 29

Experiences of four plants using monoethanolamine

31

5.1 5.2

31 31 31 31 31 32 32 32 32

5.3

5.4

5.5 6

vii

Gas composition Materials of construction 5.2.1 Carbon steels 5.2.2 Special carbon steels 5.2.3 Special stainless steels 5.2.4 Overlays, cladding and coating 5.2.5 Stress-relieving policy Operating parameters 5.3.1 Amine parameters and foaming 5.3.2 Acid gases, heat-stable amine salts, velocities and reboiler temperatures 5.3.3 Make-up water 5.3.4 Solids present and filtration 5.3.5 O2 leakage 5.3.6 Inlet gas knock-out vessel 5.3.7 Design factors Corrosion control 5.4.1 Treatments 5.4.2 Monitoring 5.4.3 Control parameters Corrosion problems experienced

32 32 32 33 33 33 33 33 33 33 33

Experiences of one plant using diisopropanolamine

35

6.1 6.2

35 35 35 35 36 36 36 36 36

6.3

Gas composition Materials of construction 6.2.1 Carbon steels 6.2.2 Special carbon steels 6.2.3 Special stainless steels 6.2.4 Overlays, cladding and coating 6.2.5 Stress-relieving policy Operating parameters 6.3.1 Amine parameters and foaming 6.3.2 Acid gases, heat-stable amine salts, velocity and reboiler temperature 6.3.3 Make-up water 6.3.4 Solids present and filtration 6.3.5 O2 leakage

36 36 36 37

viii

Contents

6.4

6.5

6.3.6 Inlet gas knock-out vessel 6.3.7 Design factors Corrosion control 6.4.1 Treatments 6.4.2 Monitoring 6.4.3 Control parameters Corrosion problems experienced

37 37 37 37 37 37 37

European Federation of Corrosion (EFC) publications: Series introduction

The EFC, incorporated in Belgium, was founded in 1955 with the purpose of promoting European co-operation in the fields of research into corrosion and corrosion prevention. Membership of the EFC is based upon participation by corrosion societies and committees in technical Working Parties. Member societies appoint delegates to Working Parties, whose membership is expanded by personal corresponding membership. The activities of the Working Parties cover corrosion topics associated with inhibition, education, reinforcement in concrete, microbial effects, hot gases and combustion products, environment-sensitive fracture, marine environments, refineries, surface science, physico-chemical methods of measurement, the nuclear industry, the automotive industry, computer-based information systems, coatings, tribo-corrosion and the oil and gas industry. Working Parties and Task Forces on other topics are established as required. The Working Parties function in various ways, e.g. by preparing reports, organising symposia, conducting intensive courses and producing instructional material, including films. The activities of Working Parties are co-ordinated, through a Science and Technology Advisory Committee, by the Scientific Secretary. The administration of the EFC is handled by three Secretariats: DECHEMA e.V. in Germany, the Société de Chimie Industrielle in France, and The Institute of Materials, Minerals and Mining in the UK. These three Secretariats meet at the Board of Administrators of the EFC. There is an annual General Assembly at which delegates from all member societies meet to determine and approve EFC policy. News of EFC activities, forthcoming conferences, courses, etc., is published in a range of accredited corrosion and certain journals throughout Europe. More detailed descriptions of activities are given in a Newsletter prepared by the Scientific Secretary. The output of the EFC takes various forms. Papers on particular topics, e.g. reviews or results of experimental work, may be published in scientific and technical journals in one or more countries in Europe. Conference proceedings are often published by the organisation responsible for the conference. ix

x

European Federation of Corrosion (EFC) publications

In 1987 the then Institute of Metals was appointed as the official EFC publisher. Although the arrangement is non-exclusive and other routes for publication are still available, it is expected that the Working Parties of the EFC will use The Institute of Materials, Minerals and Mining for publication of reports, proceedings, etc., wherever possible. The name of The Institute of Metals was changed to The Institute of Materials on 1 January 1992 and to The Institute of Materials, Minerals and Mining with effect from 26 June 2002. The series is now published by Woodhead Publishing and Maney Publishing on behalf of The Institute of Materials, Minerals and Mining. P. McIntyre EFC Series Editor The Institute of Materials, Minerals and Mining, London, UK EFC Secretariats are located at: Dr B. A. Rickinson European Federation of Corrosion, The Institute of Materials, Minerals and Mining, 1 Carlton House Terrace, London, SW1Y 5DB, UK Dr J. P. Berge Fédération Européenne de la Corrosion, Société de Chimie Industrielle, 28 rue Saint-Dominique, F-75007 Paris, FRANCE Professor Dr G. Kreysa Europäische Föderation Korrosion, DECHEMA e. V., Theodor-HeussAllee 25, D-60486, Frankfurt, GERMANY

Volumes in the EFC series

1 Corrosion in the nuclear industry Prepared by the Working Party on Nuclear Corrosion 2 Practical corrosion principles Prepared by the Working Party on Corrosion Education (Out of print) 3 General guidelines for corrosion testing of materials for marine applications Prepared by the Working Party on Marine Corrosion 4 Guidelines on electrochemical corrosion measurements Prepared by the Working Party on Physico-Chemical Methods of Corrosion Testing 5 Illustrated case histories of marine corrosion Prepared by the Working Party on Marine Corrosion 6 Corrosion education manual Prepared by the Working Party on Corrosion Education 7 Corrosion problems related to nuclear waste disposal Prepared by the Working Party on Nuclear Corrosion 8 Microbial corrosion Prepared by the Working Party on Microbial Corrosion 9 Microbiological degradation of materials – and methods of protection Prepared by the Working Party on Microbial Corrosion 10 Marine corrosion of stainless steels: chlorination and microbial effects Prepared by the Working Party on Marine Corrosion 11 Corrosion inhibitors Prepared by the Working Party on Inhibitors (Out of print)

xi

xii

Volumes in the EFC series

12 Modifications of passive films Prepared by the Working Party on Surface Science and Mechanisms of Corrosion and Protection 13 Predicting CO2 corrosion in the oil and gas industry Prepared by the Working Party on Corrosion in Oil and Gas Production (Out of print) 14 Guidelines for methods of testing and research in high temperature corrosion Prepared by the Working Party on Corrosion by Hot Gases and Combustion Products 15 Microbial corrosion Prepared by the Working Party on Microbial Corrosion 16 Guidelines on materials requirements for carbon and low alloy steels for H2S-containing environments in oil and gas production Prepared by the Working Party on Corrosion in Oil and Gas Production 17 Corrosion resistant alloys for oil and gas production: guidance on general requirements and test methods for H2S service Prepared by the Working Party on Corrosion in Oil and Gas Production 18 Stainless steel in concrete: state of the art report Prepared by the Working Party on Corrosion of Reinforcement in Concrete 19 Sea water corrosion of stainless steels – mechanisms and experiences Prepared by the Working Parties on Marine Corrosion and Microbial Corrosion 20 Organic and inorganic coatings for corrosion prevention – research and experiences: papers from EUROCORR ’96 21 Corrosion–deformation interactions: CDI ’96 in conjunction with EUROCORR ’96 22 Aspects on microbially induced corrosion Papers from EUROCORR ’96 and the EFC Working Party on Microbial Corrosion 23 CO2 corrosion control in oil and gas production – design considerations Prepared by the Working Party on Corrosion in Oil and Gas 24 Electrochemical rehabilitation methods for reinforced concrete structures: a state of the art report Prepared by the Working Party on Corrosion of Reinforced Concrete

Volumes in the EFC series

xiii

25 Corrosion of reinforcement in concrete monitoring, prevention and rehabilitation Papers from EUROCORR ’97 26 Advances in corrosion control and materials in oil and gas production Papers from EUROCORR ’97 and EUROCORR ’98 27 Cyclic oxidation of high temperature materials Proceedings of an EFC Workshop, Frankfurt–Main, 1999 28 Electrochemical approach to selected corrosion and corrosion control studies Papers from 50th ISE Meeting, Pavia, 1999 29 Microbial Corrosion (Proceedings of the 4th International EFC Workshop) Prepared by the Working Party on Microbial Corrosion 30 Survey of literature on crevice corrosion (1979–1998): mechanisms, test methods and results, practical experience, protective measures and monitoring Prepared by F. P. Ijsseling and the Working Party on Marine Corrosion 31 Corrosion of reinforcement in concrete: corrosion mechanisms and corrosion protection Papers from EUROCORR ’99 and the Working Party on Corrosion of Reinforcement in Concrete 32 Guidelines for the compilation of corrosion cost data and for the calculation of the life cycle cost of corrosion – a working party report Prepared by the Working Party on Corrosion in Oil and Gas Production 33 Marine corrosion of stainless steels: testing, selection, experience, protection and monitoring Edited by D. Féron on behalf of Working Party 9 on Marine Corrosion 34 Lifetime modelling of high temperature corrosion processes Proceedings of an EFC Workshop 2001. Edited by M. Schütze, W. J. Quadakkers and J. R. Nicholls 35 Corrosion inhibitors for steel in concrete Prepared by a Task Group of Working Party 11 on Corrosion of Reinforcement in Concrete 36 Prediction of long term corrosion behaviour in nuclear waste systems Edited by D. Féron and Digby D. Macdonald on behalf of Working Party 4 on Nuclear Corrosion

xiv

Volumes in the EFC series

37 Test methods for assessing the susceptibility of prestressing steels to hydrogen induced Edited by B. Isecke on behalf of EFC WP 11 on Corrosion of Reinforcement in Concrete 38 Corrosion of reinforcement in concrete: mechanisms, monitoring, inhibitors and rehabilitation techniques Edited by M. Raupach, B. Elsener, R. Polder and J. Mietz on behalf of Working Party 11 on Corrosion of Steel in Concrete 39 The use of corrosion inhibitors in oil and gas production Edited by J. W. Palmer, W. Hedges and J. L. Dawson 40 Control of corrosion in cooling waters Edited by J. D. Harston and F. Ropital 41 Metal dusting, carburisation and nitridation Edited by M. Schütze and H. Grabke 42 Corrosion in refineries Edited by J. D. Harston 43 The electrochemistry and characteristics of embeddable reference electrodes for concrete Prepared by R. Myrdal on behalf of Working Party 11 on Corrosion of Steel in Concrete 44 The use of electrochemical scanning tunnelling microscopy (EC–STM) in corrosion analysis: reference material and procedural guidelines Prepared by R. Lindström, V. Maurice, L. Klein and P. Marcus on behalf of Working Party 6 on Surface Science 45 Local probe techniques for corrosion research Edited by R. Oltra, V. Maurice, R. Akid and P. Marcus on behalf of Working Party 8 on Physico-chemical Methods of Corrosion Testing 46 Amine unit corrosion in refineries Prepared by J. D. Harston and F. Ropital on behalf of Working Party 15 on Corrosion in the Refinery Industry 47 Novel approaches to the improvement of high temperature corrosion resistance Edited by M. Schütze and W. Quadakkers on behalf of Working Party 3 on Corrosion in Hot Gases and Combustion Products 48 Corrosion of metallic heritage artefacts: investigation, conservation and prediction of long term behaviour Edited by P. Dillmann, G. Béranger, P. Piccardo and H. Matthiessen on behalf of Working Party 4 on Nuclear Corrosion

Volumes in the EFC series

xv

49 Electrochemistry in light water reactors: reference electrodes, measurement, corrosion and tribocorrosion issues Edited by R.-W. Bosch, D. Féron and J.-P. Celis on behalf of Working Party 4 on Nuclear Corrosion 50 Corrosion behaviour and protection of copper and aluminium alloys in seawater Edited by D. Féron on behalf of Working Party 4 on Nuclear Corrosion 51 Corrosion issues in light water reactors: stress corrosion cracking Edited by D. Féron and J.-M. Olive on behalf of Working Party 4 on Nuclear Corrosion

xvi

1 Introduction

The European Federation of Corrosion (EFC) Refinery Corrosion Working Party 15 has discussed a wide variety of topics since its first meeting in 1996. At one meeting a presentation was made on corrosion associated with amine units and this subject received much interest from the members. As a result of this it was decided that it would be beneficial to carry out a survey of corrosion on the amine units with which the members were associated. This was seen as a good topic for investigation for a number of reasons: ∑ Many sites had experienced various corrosion and cracking problems associated with this type of plant and some of these had been shared with the group. ∑ Some sites were in the process of changing from one type of amine to another; so it was of interest to see whether any differences exist between corrosion-related problems with the different types of amine. ∑ Corrosion on amine units is fairly complex since it involves various corrosion, erosion and cracking mechanisms and is affected significantly by process parameters and the materials of construction. ∑ The subject was also thought to be non-proprietary and therefore participants did not have reservations about sharing their data. Anonymity of the data supplied was, however, preserved by participants sending in their data to the group via the EFC Scientific Secretary. The amine unit corrosion survey covered the following amine types: ∑ ∑ ∑ ∑

Methyldiethanolamine (MDEA). Diethanolamine (DEA). Monoethanolamine (MEA). Diisopropanolamine (DIPA).

The findings of the survey emphasise the importance of careful process control and the beneficial effect of upgrading to austenitic stainless steel in a number of areas. 1

2

Amine unit corrosion in refineries

2 Technical background

There is already a significant amount of information in the literature on corrosion in amine units. The following is an overview of the issues involved.

2.1

Process issues

2.1.1

Pretreatment

Units often use a knock-out pot before the absorber where liquid hydrocarbon and water are removed.

2.1.2

Absorber

In the absorber, the amine removes H2S, CO2 and mercaptans by forming a salt. MEA, DEA, MDEA, DIPA and diglycolamine (DGA) are the main amines that are used. Lean amine flows down the absorber in counterflow to the fluid that is being treated, which exits at the top with the impurities substantially removed. The amine that has absorbed the impurities is then referred to as rich amine and exits from the bottom of the absorber and flows to a regenerator. Several absorbers may feed a common regenerator. The amine will also remove stronger acids in the absorber such as formic acid (amongst others) and the reaction with these acids is difficult to reverse, causing a build-up of heat-stable amine salts (HSAS) in the amine.

2.1.3

Regenerator

Rich amine goes to the lean–rich exchanger and then on to the regenerator. Rich amine passes on the tube side to avoid pressure changes and flashing. In the regenerator, acid gases are stripped by reduction in pressure and increase in temperature. Heat is provided by a reboiler, the temperature of which needs to be carefully controlled in order to reduce degradation of the 3

4

Amine unit corrosion in refineries

amine. The amine salt liberates the acid gas, which exits to the overhead, and lean amine, which exits from the bottom and is filtered.

2.2

Important issues

Important issues to be considered are: ∑ ∑ ∑ ∑ ∑ ∑ ∑ ∑

Amine type and strength. Acid gas loading. Temperature. HSAS. Solids and filtration. Wet H2S cracking. Amine cracking. Species found in regenerator overheads.

2.3

Corrosion issues

2.3.1

General factors

The amine itself is not corrosive, but corrosion is promoted by the following: ∑ ∑ ∑ ∑ ∑ ∑

Entrained acid gases. Higher concentration of corrosive species. Higher temperatures. Corrosion on heat transfer surfaces. Higher velocities. HSAS.

2.3.2

Mechanisms

Wet H2S corrosion Fe + H2S = FeS + H2 FeS is more protective than FeCO3. Wet CO2 corrosion Fe + H2CO3 = FeCO3 + H2 Wet CO2 corrosion can result in high corrosion rates, but a carbonate film gives some protection and is more protective at higher temperatures. The CO2 content is often not very high in refinery streams, except in hydrogen reformer plant systems.

Technical background

2.3.3

5

Rich amine

Corrosion in rich amine solutions is increased by high acid gas loading, and the loading often has to be limited to minimise corrosion. Acid gas flashing disturbs the FeS protective films. Acid gases break out of solution to give acid attack when there is a high velocity and high temperature and when the pressure is too low to suppress vaporisation.

2.3.4

Lean amine

It is important to avoid too low a level of H2S in the lean amine, as a small amount of H2S is helpful in producing a protective sulphide film. Primary amines are more corrosive than secondary and tertiary amines.

2.3.5

Acid gas attack

H2S forms protective sulphide films on carbon steel in many areas but there are problems in areas where films can be removed. In such locations, upgrading of materials is required, often to an austenitic stainless steel belonging to the 300 series.

2.3.6

Heat-stable amine salts

Heat-stable amine salts (HSAS) form from stronger acids than H2S and CO2 and they do not thermally break down at regeneration temperatures. Problems arise from formic, oxalic, acetic and thiosulphurous acids and from chlorides, sulphates, thiosulphates and thiocyanates which can come in from the feed system. Oxygen is also a source of problems and this can come in from the feed, amine storage and make-up water. Blanketing tanks with N2 and maintaining a tight system are helpful in order to exclude oxygen. High temperatures are also a problem and temperatures should be minimised through control of the reboiler temperature. HSAS can also be produced from CO and HCN. Therefore, some operators treat gas from fluid catalytic cracking units (FCCUs) with polysulphide to remove HCN. The presence of HSAS reduces acid gas removal capacity, lowers pH, increases conductivity and dissolves protective films; so HSAS should be minimised as much as possible.

2.3.7

Make-up water quality

Make-up water should ideally have low total dissolved solids and low total hardness owing to calcium, low chlorides, sodium, potassium and dissolved iron and should exclude oxygen.

6

2.3.8

Amine unit corrosion in refineries

Erosion corrosion

Erosion corrosion is caused by dirty amine solutions containing solid particulates; therefore lean amine is filtered to minimise solids. Protective FeS films can be damaged and removed under conditions of high velocity, turbulence or impingement. Benefit can therefore, be obtained by designing to minimise impingement and turbulence, e.g. by using large radius bends. The velocity in piping is usually kept below 1 m s–1, and 300 series stainless steel is required at pressure let-down valves.

2.3.9

Proprietary chemical additions

Some operators utilise proprietary chemical additions from their site chemical supplier, although many prefer not to use these.

2.3.10 Corrosion in regenerator overheads Corrosion in the overheads of the regenerator takes a different form from that occurring elsewhere in the amine unit. H2S, NH3 and HCN are important species that are involved, which can give corrosion. Conditions are more aggressive when treating streams from cokers, visbreakers, FCCUs and hydroprocessors. NH4HS can be particularly aggressive, and close attention needs to be paid to concentration and velocity with this species. HCN is detrimental as it removes sulphide scales, which increases corrosion and promotes hydrogen pick-up and damage: FeS + 6 CN – = Fe(CN) 64– + S 2–

Special attention is needed in order to avoid excessive accumulation of NH4HS and HCN in the regenerator overhead reflux system.

2.3.11 Hydrogen-related cracking in wet H2S systems Sulphide stress cracking is prevented by minimising the hardness and strength of the alloys used for wet H2S systems. This is accomplished through material selection, and the control of weld procedures and post-weld heat treatment (PWHT). Hydrogen-(pressure-)induced cracking (HIC), including stress-orientated hydrogen-induced cracking (SOHIC), is mitigated by the use of improvedquality steel plate and PWHT or the use of corrosion-resistant alloy cladding.

2.3.12 Alkaline stress corrosion cracking API 945 recommends PWHT as follows:

Technical background

∑ ∑ ∑ ∑

7

MEA: PWHT for service at all temperatures. DIPA: PWHT for all temperatures. DEA: PWHT for temperatures of 60 ∞C (140 ∞F) and above. MDEA: PWHT for service at temperatures of 82 ∞C (180 ∞F) and above.

It is also necessary to take care of steam-out conditions.

2.4

Materials

Carbon steel can be used with success for many areas but material upgrading is necessary in highly corrosive areas. Use has been made of materials such as the austenitic stainless steels 304L and 316L, 2205 duplex stainless steel and other high-alloy materials such as Alloy C or Stellite for valve trim.

8

Amine unit corrosion in refineries

3 Experiences of ten plants using methyldiethanolamine

The plant numbers are given in parentheses.

3.1

Gas composition

Recycle gas: H2S, 1148 kg mol h–1; CO2, 0.816 kg mol h–1 Cold rich gas: H2S, 36.170 kg mol h–1; CO2, 2.176 kg mol h–1

(1)

H2S, CO2, NH3

(2)

H2S, CO2, NH3, HCN

(3)

H2S, CO2

(4)

90% H2S, 6% CO2

(5)

Not available (N/A) 1.5% H2S, 3.3% CO2 0.1% H2S, 13–14% CO2

3.2

Materials of construction

3.2.1

Carbon steels

Typical: <0.16% C, <0.025% S, <0.03% P, killed CS

(6), (7), (8) (9) (10)

(1)

N/A

(2), (3)

A42

(4)

<0.2% C, <0.03% S, <0.035% P

(5)

A516 Gr. 70

(6), (10)

A516 Gr. 60

(7), (8), (9) 9

10

3.2.2

Amine unit corrosion in refineries

Special carbon steels

None

(1), (6), (7), (8), (9), (10)

N/A

(2), (3)

Z35

(4)

0.001–0.005% S, 0.015–0.028% P; Dillinger

(5)

One A516-65(Z35) reflux drum

(9)

3.2.3

Special stainless steels

None

(1)

N/A

(2), (3)

Regenerator rich amine inlet: 304 stainless steel Top section of the tower: 304L stainless steel Regenerator reboiler tubes: 18% Cr, 2% Mo and tube sheet Cronifer 2205LCN Reboilers, shells, tubes, baffles: 304 stainless steel Reboilers, tubes: 18/8 steel Reboilers, tubes: 316L stainless steel Absorber internals: 304L stainless steel Feed-effluent exchanger tubes: Ti grade 2 Feed-effluent exchanger tubes: type 321 Packing rings in regenerator: stainless steel

(4) (10) (5) (6), (7) (9) (10) (6) (6), (7) (9) (8), (10)

Pump bodies and impellers: now stainless steel

(10)

Some rich amine pipework: 304L stainless steel

(10)

Lean amine pipework: 304L stainless steel

(10)

3.2.4

Overlays, cladding and coating

No N/A Reboiler shell: 1.4571 clad with 316L stainless steel Regenerator bottoms: clad with 316L stainless steel

(1), (4), (8) (2), (3) (5) (6), (7)

Experiences of ten plants using methyldiethanolamine

Regenerator bottoms: Belzona 1391

11

(10)

Regenerator reflux drum: clad with 316L stainless steel

(6), (7)

Regenerator reflux drum: Sakaphen coating

(9)

Feed bottoms tube sheet: clad with Ti

(6), (7)

Reflux drum: clad with 316L stainless steel

3.2.5

(7)

Stress-relieving policy

Not known

(1)

Systematic stress relief

(2), (3), (4), (10)

Old, no; new, yes at any temperature

(5)

Yes, all including sour gas piping

3.3

Operating parameters

3.3.1

Amine parameters and foaming Amine

Concentration Circulation (%)

Ucarsol HS 101 35–45 47, 12 and 10 m3 h–1 (three absorbers) 30 60 t h–1 40 130 t h–1 40–50 25–50 t h–1 Ucarsol HS 115 40–45 50 t h–1 45 200 m3 h–1 35 200 m3 h–1 ? 40 m3 h–1 45 100 m3 h–1 50

(6), (7), (8), (9)

Loss (t a–1)

Foaming

Plant

12

No

(1)

10 10 20

No No Sometimes

(2) (3) (4)

12 50 (40% inventory) 160 (110% inventory) No information 20 (30% inventory) ?

No No Serious No information No Sometimes

(5) (6) (7) (8) (9) (10)

12

Amine unit corrosion in refineries

3.3.2

Acid gases, heat-stable amine salts, velocities and reboiler temperatures

Acid gases (mol mol–1) In rich amine

In lean amine

0.523 and 0.33 0.175 0.245 0.175–0.44

0.077 and 0.077 0.01–0.02 0.01 0.0175–0.03

0.3 0.45–0.50 0.25–0.40 N/A 0.05–0.01? 0.45–0.50

0.005 0.002–0.0015 0.010–0.035 N/A <0.01 0.005–0.09

HSAS* (%)

Velocity (m s–1)

Reboiler temperature (∞C)

Plant

<0.1 0.7 0.2 Not identified 0.8–1.5 0.5–2.5 0.5–3.0 N/A 0.5–1.5 0.25

OK OK OK OK

120 121 148 118

(1) (2) (3) (4)

1.7 N/A N/A N/A N/A 1.9–2.0 (7 near pumps)

140 133 133 N/A 133 130–140

(5) (6) (7) (8) (9) (10)

*The HSAS entries can be further described as follows: <0.1%

(1)

0.7%; acetates, formates, sulphates, thiosulphates

(2)

0.2%; acetates, formates, sulphates, thiosulphates

(3)

Not identified

(4)

0.8–1.5%; neutralise with K2CO3

(5)

0.5–2.5%; total 45 000 ppm acetate, formate, glycolate, lactate, oxalate, proprionate, sulphate, thiocyanate

(6)

0.5–3.0%; total 40 000 ppm acetate, formate, glycolate, lactate, oxalate, proprionate, sulphate, thiosulphate, thiocyanate

(7)

N/A

(8)

0.5–1.5; total 5800 ppm acetate, formate, glycolate, oxalate, proprionate, sulphate, thiocyanate, thiosulphate

(9)

0.25%; acetate, thiosulphate, oxalate, sulphate, formate

(10)

Experiences of ten plants using methyldiethanolamine

3.3.3

Make-up water

Condensate Demineralised Boiler feed water

(1), (5) (2), (3), (4), (10) (6), (7), (9)

N/A

3.3.4

13

(8)

Solids present and filtration

Candle filter in the regenerator amine circle

(1)

10% circulated amine on the mechanical filter; 3% on the charcoal absorber

(2), (4)

10% circulated amine on the mechanical filter

(3)

No solids; precoat filter

(5)

Solids, up to 20 mg per 100 ml–1; Vacco filters on the slipstream, 10 mm (5–10% circulation); followed by an activated C filter for hydrocarbons

(6)

Solids, up to 15 mg per 100 ml; Vacco filters on the slipstream, 10 mm (5–10% circulation); followed by an activated C filter for hydrocarbons

(7)

N/A

(8)

No solids (maximum, 0.01 mg per 100 ml–1); Vacco filters on the slipstream, 10 mm (10% circulation); followed by an activated C filter for hydrocarbons

(9)

Full stream particulate; 10% slipstream activated C

3.3.5

O2 leakage

No

(1), (2), (3), (4)

Not known No, and passivation step after opening the vessels to the atmosphere 2–3% O2 in blanketing N2 on the make-up tank

3.3.6

(10)

(5), (8) (6), (7), (9) (10)

Inlet gas knock-out vessel

Not known

(1), (8)

14

Amine unit corrosion in refineries

Yes

(2), (3), (4), (6), (7)

No

(5)

N/A, one with a water wash tower in front

(9)

KO + filter, two stages, 5 mm and 1 mm

3.3.7

(10)

Design factors

There are some problems

(1)

Control valve close to the regenerator

(2), (3), (4)

1.5 D elbows N/A

(5) (6), (7), (8), (9), (10)

3.4

Corrosion control

3.4.1

Treatments

None

(1), (2), (3), (4), (10)

No inhibitor; neutralise HSASs with K2CO3 Corrosion inhibitor in the overheads and K2CO3 for HSAS

(5) (6), (7)

CN scavenger in the wash water on the FCCU

(8)

N/A

(9)

3.4.2

Monitoring

Wall thickness measurements

(1)

Fe, amine, HSAS

(2)

Fe, H2S, HSAS

(3)

Fe, H2S

(4)

Corrosion coupons in the reboiler vapour line, HSAS, 2% maximum

(5)

Corrosion coupons, HSAS, 2% maximum, 1% target; amine loading, H2S, lean 0.01 mol mol–1 maximum and rich 0.40 mol mol–1 maximum; suspended material, 1 mg per 100 ml maximum; K, 30 000 ppm maximum; soluble Fe, 10 ppm maximum; soluble Mn, 2 ppm maximum; record soluble Ni, Cr, Cl–, Na, Ca

(6), (7)

Experiences of ten plants using methyldiethanolamine

15

H2S in sweet gas, 100 ppm maximum

(8)

Corrosion coupons, HSAS, 3% maximum, 1% target; Amine loading, H2S, lean 0.01 mol mol–1 maximum rich 0.40 mol mol–1 maximum; suspended material, 1 mg per 100 ml maximum; K, 30 000 ppm maximum; soluble Fe, 10 ppm maximum; soluble Mn, 2 ppm maximum; record soluble Ni, Cr, Cl–, Na, Ca

(9)

–

Fe, Cr, amines, HSAS, Cl , corrosivity; wall thickness measurements on the stripper; electrical resistance (ER) probe and coupons on the bottom of the outlet of the contactor; ER probe and coupons on the vapour–liquid feed into the stripper

3.4.3

(10)

Control parameters

No

(1), (10)

N/A

(2), (3), (4)

Overheads: 1 ppm Fe; 4.7% NH4HS (no draining) pH 8 maximum; total salts and conductivity; bleed of the reflux water adjusted accordingly –

CN scavenger in the wash water from the FCCU

3.5

(5) (6), (7), (9) (8)

Corrosion problems experienced

Desorbers reflux line and pumps N/A

(1) (2), (3)

Regenerator reboiler: corrosion of tubes on the shell side

(4)

Regenerator reboiler: corrosion of the vapour section, now clad with stainless steel

(5)

Regenerator reboiler: stress corrosion cracking (SCC) of 316 stainless steel tubes

(10)

Rich amine feed preheater: SCC, now stress relieved

(5)

Rich amine line: from the valve to the column corroded, move the valve closer to the column

(5)

Lean amine general: H2S lean loading too low, increase from 100 ppm to >600 ppm

(5)

16

Amine unit corrosion in refineries

High pressure (HP) absorber: uniform corrosion of the vessel wall from the normal amine level to the top of packing at the side of the gas inlet nozzle for 180∞ of circumference (note too low amine circulation rates with too high H2S loading of the amine solution).

(6)

Ti tube failure

(6), (7)

Regenerator: corrosion at the level of the reboiler vapour return line, now extend the stainless steel clad into this zone

(7), (9)

Regenerator: corrosion at the level of the reboiler vapour return line corrosion of the internal ladders

(10)

Vapour return line: carbon steel, severe corrosion and erosion, now replaced by stainless steel piping None

(7), (9) (8)

Pumps: erosion of pump bodies

(10)

Fin-fan heat exchanger: erosion of carbon steel tubes, to be replaced by stainless steel

(10)

Piping: corrosion near bends; corrosion near the inlet and outlet of the pumps (diameter reduction); replace with stainless steel; vibration on rich amine line caused fretting-type failure at the pipe supports

(10)

A summary of selected data is presented in Section 3.6.

3.6

Summary of selected data Acid gases (mol mol–1) ——————————————— In rich amine In lean amine

HSAS (%)

Reboiler temperature (∞C)

Corrosion problems

35–45

0.52–0.33

0.08–0.08

<0.1

120

Desorbers reflux line and pumps

(1)

30

0.18

0.01–0.02

0.7

121

N/A

(2)

40

0.25

0.01

40–50

0.18–0.44

0.02–0.03

40–45

0.3

45

35

0.2

Plant

N/A

(3)

118

Regenerator reboiler: corrosion of tubes on the shell side

(4)

0.005

0.8–1.5

140

Regenerator reboiler: corrosion of the vapour section; now clad with stainless steel Rich amine feed preheater: SCC; now stress relieved Rich amine line: From the valve to the column corroded; move the valve closer to the column Lean amine general: H2S lean loading too low; increase from 100 to 600 ppm

(5)

0.45–0.50

0.001 52–0.002

0.5–2.5

133

HP absorber: corrosion of the vessel wall from the normal amine level to the top of packing at side of the gas inlet nozzle for 180∞

(6)

0.25–0.40

0.010–0.035

0.5–3.0

133

Ti tube failure Regenerator: corrosion at the level of reboiler vapour return line;

(7)

17

148

N/A

Experiences of ten plants using methyldiethanolamine

Amine concentration (%)

18

Summary of selected data continued Acid gases (mol mol–1) ——————————————— In rich amine In lean amine

HSAS (%)

Reboiler temperature (∞C)

Corrosion problems

Plant

now the stainless steel clad has been extended into this zone Vapour return line: severe corrosion and erosion; now replaced by stainless steel piping ?

N/A

N/A

45

0.05–0.01?

<0.01

50

0.45–0.5

0.005–0.09

N/A 0.5–1.5

0.25

N/A

None

(8)

133

Regenerator: corrosion at the level of the reboiler vapour return line; now the stainless steel clad has been extended into this zone Vapour return line: severe corrosion and erosion; now replaced by stainless steel piping

(9)

133

Regenerator reboiler: SCC of 316 stainless steel tubes Regenerator: corrosion at the level of the reboiler vapour return line; corrosion of internal ladders Pumps: erosion of pump bodies Fi-fan heat exchanger: erosion of carbon steel tubes; replaced by stainless steel Piping: corrosion near bend, near inlet and outlet of pumps; replaced with stainless steel; vibration on rich amine line caused fretting-type failure

(10)

Amine unit corrosion in refineries

Amine concentration (%)

4 Experiences of twenty-one plants using diethanolamine

The plant numbers are given in parentheses.

4.1

Gas composition

H2S, CO2, NH3, HCN

(1), (6), (7)

H2S

(2)

H2S, CO2

(3)

H2S, NH3

(4), (9)

H2S, CO2, NH3

(5), (8)

70% H2S, 20% CO2, 7% H2O, 3% NH3

(10)

Not known

(11)

90% H2S, 8.6% CO2, 0.3% H2, 0.3% C1, 0.4% C2, 0.4% C3

(12)

2% H2S, 2.6% CO2, 4.8% H2

(13)

Liquefied petroleum gas: (LPG) 35% C3, 61% C4, 4% H2S

(14)

Visbreaker, 2–14 mol% H2S (average 7 mol% H2S), 1% CO2, 1% CO; FCCU, 4–5% H2S

(15)

H2S

(16)

4000 ppm H2S

(17)

26.4% H2S, 1.5% CO + N2

(18)

Ex-hydrocarbon treatment unit and hydrodesulphurisation, H2S

(19)

Dry gas ex-FCCU, H2S + CO2, C3, fuel gas

(20)

Several feeds H2S + CO2

(21) 19

20

Amine unit corrosion in refineries

4.2

Materials of construction

4.2.1

Carbon steels

A42

(1), (2), (3), (4), (5), (6), (7), (8), (16)

N/A

(9), (10), (12), (21)

A106B

(11)

0.15% C, 1.35% Mn, 0.02% S, 0.018% P, 0.33% Si, 0.027% Ni, 0.015% Cr, 0.002%, Mo, 0.007% Cu, 0.018% Al

(13)

Absorber A516 Cr 70; regenerator A285C

(14)

No information

(15)

<0.3% C, <0.025% S and P, 0.1% Si minimum, 0.3–1.0% Mn

(17), (18)

Plain carbon steel, <0.23% C, <0.45% Ceq; Vickers hardness (load, 20 kgf), <248 HV 20

(19)

Normal carbon steel, <0.43% Ceq; Vickers hardness (load, 20 kgf), <245 HV 20 typically; A42C1, A42C3, A285C, A37C3SR, A37CS3, A106A, A42AP, A515Gr60, A106B, A516Gr60, A179

(20)

4.2.2

Special carbon steels

None

(1), (4), (5), (6), (7), (11), (14), (15), (17), (18), (19)

Z15 absorbers; Z35 regenerators and overhead drums

(2)

Z35

(3)

Z35 absorbers, gas separator, regenerator and O–H drum

(8)

N/A

(9), (10)

Fe 42.2; regenerator reboiler built to API 5LB

(12)

Z grade used where free sour gas absorber

(13)

HIC-resistant regenerator overheads tower drum

(16)

No, but new equipment will be in Z quality

(20)

Not known

(21)

4.2.3 None

Special stainless steels (1), (15), (17), (19), (20)

Experiences of twenty-one plants using diethanolamine

Rich amine inlet pipe to the regenerator: 304 stainless steel

21

(2), (3), (4), (7)

Overhead regenerator’s drum reflux pump

(5)

Regenerator overheads tubes: SAF 2205

(6)

Lean–rich amine heat exchanger tubes; shell and piping: 304L

(8)

Regenerator overhead condenser: SAF2205

(8)

N/A

(9), (10), (21)

Regenerator reboiler feed and return lines, also nozzles in the reboiler and lower part of the tower sleeved in stainless steel; later, reboiler shell replaced with solid stainless steel

(11)

Feed–bottom exchanger: 316L Piping: 316L in hot lean amine, reboiler

(12)

Regenerator overheads condenser, 321 stainless steel

(13)

Return line from the reboiler to the regenerator tower: 304L stainless steel

(13)

Reboiler bundles: 304 stainless steel

(13)

Vessel, internal: 304 stainless steel

(13)

Regenerator: new column, 1990, 2205 duplex

(14)

Absorber demister pad: 304 stainless steel

(14)

Packing supports: 410 stainless steel

(14)

Heat exchanger tubes at the bottom of the regenerator

(16)

Preheat and reboiler tubes: 316L stainless steel

(18)

4.2.4

Overlays, cladding and coating

None

(1), (2), (3), (4), (5), (6), (7), (8), (14), (15), (16), (17), (19), (20)

Not available

(9), (10), (21)

Reboiler shingle lined with 304 stainless steel

(11)

Regenerator overhead condenser replaced with 316L stainless steel cladding

(12)

Regenerator tower top 3.5 m clad with 304 stainless steel

(13)

Nozzles are solid 304 stainless steel

(13)

22

Amine unit corrosion in refineries

Reboiler absorber tower bottom clad with 304 stainless steel and solid 304 stainless steel nozzles

(13)

Other absorber towers not clad

(13)

Belzona and metal sprayed coatings used in regenerator for repairs

(13)

4.2.5

Stress-relieving policy

Systematic stress relief of welds

(1), (2), (3), (4), (5), (6), (7), (8), (9), (10)

Original stress relief on lean amine return from regenerator to the last of the three feed–effluent exchangers; following cracking in some other lines, replaced with stress-relieved lines

(11)

Regenerator piping stress relieved

(12)

All vessels stress relieved

(13)

All amine service pipework

(14), (15)

Always stress relieved

(16)

Yes

(17), (18)

Not applied, not mentioned

(19)

Some parts are PWHT (absorber and regenerator); all new equipment

(20)

Not known

(21)

4.3

Operating parameters

4.3.1

Amine parameters and foaming Amine

Concentration (wt%)

Circulation

22 20 25 25–30 16–30 30

40 t h–1 76 t h–1 80 t h–1 30–50 t h–1 30–65 t h–1 35 t h–1

Loss

30 t N/A N/A 27 t 10 t 67 t

a–1

a–1 a–1 a–1

Foaming

Plant

No No No Sometimes Noticed Sometimes

(1) (2) (3) (4) (5) (6)

Experiences of twenty-one plants using diethanolamine Amine Concentration (wt%)

Circulation

16–23 22–27 20–24 29 ? 25 27 20–25 20–25 25–32 20 20 26.5 16.8 30

45–65 t h–1 15–30 t h–1 64 t h–1 170 m3 h–1 ? 130 kg h–1 700–900 kl day–1 25 m3 h–1 50–20 m3 h–1 N/A 30 t h–1 300 t h–1 220 t h–1 900 t h–1 1500 t h–1

4.3.2

23

Loss

Foaming

Plant

52 t a–1 26 t a–1 14 t a–1 60 t a–1 ? 120 m3 a–1 40 t a–1 N/A N/A 105 t a–1 No 0.25 kg t–1 10 t a–1 1.5 t a–1 60.5 t a–1 (4 ¥ inventory)

No Rare Yes Yes ? Yes No Frequent No Not often No Rare or no Infrequent 1–2 per month Occasional

(7) (8) (9) (10) (11) (12) (13) (14) (15) (16) (17) (18) (19) (20) (21)

Acid gases, heat-stable amine salts, velocities and reboiler temperatures

Acid gases HSAS ————————————————————— (wt%) In rich amine In lean amine

Velocity* Reboiler Plant (m s–1) temperature (∞C)

<0.45 mol mol–1 0.45 mol mol–1 0.25–0.47 mol mol–1 0.15–0.52 mol mol–1 0.77 mol mol–1 0.1–0.26 mol mol–1 0.017–0.3 mol mol–1 0.12–0.62 mol mol–1 0.20–0.35 mol mol–1

0.01 mol mol–1 0.05 mol mol–1 0.05 mol mol–1 0.03–0.1 mol mol–1 0.004–0.4 mol mol–1? 0.005–0.02 mol mol–1 0.008–0.016 mol mol–1 0.05 mol mol–1 0.01–0.02 mol mol–1

No No No No No No No No No

0.35 mol mol–1

0.05 mol mol–1

?

?

<31 000 ppm

<800 ppm

0.41 mol mol–1

0.01 mol mol–1

1.42 N/A N/A N/A N/A 2.0 2.4 N/A 0.6 (formate and acetate) 1–5

Not known ? Not known Identified Not known <2 (1.6) Not K2CO3 known

129 124 130 125 120 123 126 128 123

(1) (2) (3) (4) (5) (6) (7) (8) (9)

N/A

(10)

N/A

(11)

126

(12)

127

(13)

24

Amine unit corrosion in refineries

Acid gases HSAS ————————————————————— (wt%) In rich amine In lean amine N/A

0.05–0.35 mol mol–1

N/A N/A

10 g l–1 H2S 36 g l–1 H2S 0.116 mol mol–1

0.05–0.35 mol mol–1 0.01 mol mol–1 (aim) 0.003 mol mol–1 (actual) 2 g l–1 H2S 4 g l–1 H2S 0.019 mol mol–1

N/A

N/A

N/A

N/A

1–3 (control by fresh feed) 1–3 N/A

Velocity* Reboiler Plant tempera(ms–1) ture (∞C) No

125

(14)

No Not known

125 N/A

(15) (16)

120 140 N/A

(17) (18) (19)

N/A

(20)

N/A

(21)

No No 0.0?

1 1.13 Not known (design value, 1.5) Up to 4.5 Not (neutra- known lise) (design value, 1.5) N/A

Not known (design value, 1.5)

* The velocity is less than 0.91 m s–1 for carbon steel and less than 2.4 m s–1 for stainless steel.

4.3.3

Make-up water

Boiler feed water Demineralised

(12) (1), (2), (3), (4), (5), (6), (7), (8), (9), (16), (17), (18)

Condensate (pH 8.8; conductivity, 8 mS cm–1) Not known

(10), (11), (14), (15)

Not known, typically condensate

4.3.4

(13)

(19), (20), (21)

Solids present and filtration

10% circulated amine on the mechanical filter; 3% on the charcoal absorber

(1), (2), (3), (4), (5), (6), (7), (8), (9)

Experiences of twenty-one plants using diethanolamine

25

Continuous

(10)

N/A

(11)

Two candle filters (Pall) for particulates filtering on a loop from the amine surge tank

(12)

Solid levels unknown; bag filters (5–10 mm); precoat filters; C filters

(13)

Low solids level, excess after upset; 10% lean amine through the mechanical filter and charcoal bed; 100% lean amine through 10 mm cartridge filters Solids level, <15 mg l

–1

(14), (15) (16)

FeS present; no filtration

(17)

Coke dust, precoat filter

(18)

45 wtppm; 10 mm Niagra; no C filter

(19)

Probably high; 10 mm Cunot cartridge + Niagra

(20)

Not known; 10 mm Niagra; no C filter

(21)

4.3.5

O2 leakage

No

(1), (4), (5), (6), (7), (8), (9), (10), (13), (14), (15), (17), (18), (19)

Not known

(2), (3), (11)

Two amine tanks open to the atmosphere

(12)

N2 blanket storage

(16)

Yes, through fluid catalytic cracking of dry gas and storage

4.3.6

(20), (21)

Inlet gas knock-out vessel

Yes

(1), (4), (6), (7), (8), (13), (15), (17), (18), (19), (20), (21)

No

(2), (3), (5)

Not known Not large enough Not applicable on LPG

(9), (11) (10), (12) (14)

26

4.3.7

Amine unit corrosion in refineries

Design factors

Control valve as close as possible to regen

(1), (2), (3), (4), (5), (6), (7), (8), (9)

Yes

(16), (17), (18)

No

(13)

Not known

(10), (11), (12), (14), (15), (19), (20), (21)

4.4

Corrosion control

4.4.1

Treatments

None

(2), (3), (4), (5), (6), (7), (8), (12), (17), (18), (19), (21)

Antifoam, 3 t a–1

(1) –1

Antifoam, 50 kg a ; inhibitor, 2.6 t a

–1

(9)

Yes

(10)

Not known

(11), (16)

Betz Petromeen W5-58 in regenerator overheads; 20 l day in an amine system of 240T and K2CO3 slug dosed; 250–500 kg in 3–6 months

–1

Overheads corrosion inhibitor

(13) (14), (15)

Nalco inhibitor replaced in August ’98 by 7% soda injection

4.4.2

(20)

Monitoring

Fe content; H2S loading

(1), (2), (3), (4), (6), (7), (8)

Fe content; H2S loading, purge 2 times per week of regenerator overheads drum

(5)

Fe content; H2S loading; HSAS; hydrocarbons

(9)

Fe contents and HSAS Not known

(10) (11), (19), (20), (21)

Routine non-destructive evaluation

(12)

ER probes in regenerator overheads, reboiler inlet and outlets; lean amine in lean–rich exchangers; weekly samples of Fe, Cu, Mn, conductivity, pH, Na, amines, HSAS, total acid gas and acid gas loading; periodic samples of filterable solids, hydrocarbon content to measure filter and activated C performance

(13)

Experiences of twenty-one plants using diethanolamine

Coupons in reboiler; monthly monitoring of amines by analysis, sulphides, HSAS

(14), (15)

Fe content

(16)

None

4.4.3

27

(17), (18)

Control parameters

Not known

(1), (2), (3), (4), (5), (6), (7), (8), (9), (11), (16), (19), (20), (21)

None

(10), (13), (17), (18)

Corrosion rates linked to regeneration temperatures, now 126 ∞C maximum, and corrosion rates have dropped Regenerator overheads, NH3 and H2S in reflux, 2 wt% maximum

4.5

Corrosion problems experienced

4.5.1

Findings for each plant

(12) (14), (15)

Regenerator reboiler tubes on the shell side of tubes; cracking in the piping for lean amine, outlet of the regenerator; purge of the regenerator overheads drum

(1)

Overhead line of the regenerator between the condenser and separator drum

(2)

Rich amine–lean amine heat exchanger tubes on the rich amine side

(3)

Blistering in the regenerator overheads condenser; blistering in the regenerator overheads separator

(4)

Corrosion of the regenerator overheads circuit

(5)

Corrosion by lean amine on the rich–lean exchanger; corrosion by rich amine on the tube side of the rich–lean exchanger

(6)

Cracking of welds on the regenerator lean amine outlet; corrosion of the rich–lean exchanger on the tubes in the rich amine; pitting of the regenerator reboiler

(7)

Pitting of the shell and tubes of the regenerator reboiler; pitting of regenerator trays

(8)

Fouling of the rich–lean amine exchanger in the rich amine

(9)

Not known

(10)

28

Amine unit corrosion in refineries

Corrosion of the reboiler shell; corrosion of the regenerator opposite the reboiler return; cracking in non-stress-relieved lines in the lean amine at 60 ∞C; corrosion on the lean amine side of the lean–rich exchanger (11) Severe corrosion behind the regenerator seal pan downcomer; blistering of the regenerator overheads drum (replaced); partition plate distortion of the amine cooler; regenerator overhead nozzle and tube corrosion (upgraded to 304 stainless steel); regenerator reboiler shell corroded; regenerator feed–bottoms exchanger shell and tubes corroded and changed to 316L stainless steel; pipework corroded (12) Regenerator reboiler shell in top adjacent to the outlet nozzle; shell nozzles now weld overlaid with 309L stainless steel and shell coated with Belzona 1321 S metal; also in the bundle, corrosion of CS baffles on the shell side, now replaced with stainless steel (tubes are 304 stainless steel); another shell weld repaired and metal sprayed with eutectic Castolin Proxon 21032S (45% Ni, 20% Fe, 20% Mo, 5% W, 10% Ti); two regenerator towers severely corroded on the side wall opposite the reboiler return inlet nozzle (attributed to high HSAS content (5%)), one tower coated with Belzona 1321 which reduced corrosion but started to break down but was not repaired as HSAS were brought under control, severe corrosion of second tower (14 mm down to 3 mm); the vessel metal sprayed with 1804 wire (75% Ni, 8% Cr, 5% Fe, 5% Mo, 7% Al); surface built up with Belzona 1311 (R metal) and coated with two coats of Belzona 1321 S metal, subsequently replaced with a 304 stainless steel clad section

(13)

Regenerator reboiler continually corroded with pitting and wastage, replaced in 1990 with SAF2205 tubes and clad tube sheet; lean–rich exchanger bundle retubed in 1988 and 1996, erosion at bundle baffle–shell interface, shell repairs anticipated soon

(14)

Continual tube pitting of regenerator reboiler, the bundle replaced in 1990 and 1996, shell vapour space surfaces corroded to 50% of allowance; lean–rich exchanger had minor pitting, no serious problems

(15)

Blistering of the regeneration tower top dome, also clogging of relief valves and some corrosion and erosion

(16)

Cracking of the regenerator column and grinding; retube of the reboiler

(17)

Experiences of twenty-one plants using diethanolamine

29

Corrosion in the regenerator, reboiler and preheat; cracking in the head of the preheat and in the absorber

(18)

No significant corrosion problems; regenerator overheads air cooler carbon steel life, 8 years (0.2 mm a–1)

(19)

Regenerator reboiler tubes (now neutralise acids in the solvent vapour return line from the reboiler and use line insulation to prevent condensation); neutralisation of acids in lean and fat solvent line work; reduction in solvent velocity by increasing the line size, also reducing the temperature and increasing the DEA strength

(20)

No corrosion

(21)

4.5.2

Location of problems per item of equipment

Regenerators

(7), (8), (11), (12), (13), (16), (17), (18)

Regenerator overheads drum

(1), (4), (5), (12)

Regenerator overheads condenser Regenerator overheads piping

(4), (5), (12) (2), (5)

Regenerator reboiler

(1), (7), (8), (11), (12), (13), (14), (15), (17), (18), (20)

Rich–lean exchanger

(3), (6), (7), (9), (11), (12), (14), (18)

Lean amine

(1), (11)

30

Amine unit corrosion in refineries

5 Experiences of four plants using monoethanolamine

The plant numbers are given in parentheses.

5.1

Gas composition

11.04% H2S

(1)

16.24% H2S

(2), (3)

20.00% H2S

(4)

5.2

Materials of construction

5.2.1

Carbon steels

<0.3% C, <0.025% S and P, 0.1% Si minimum, 0.3–1.0% Mn

(1), (2), (3)

0.13% C, 0.007% S, 0.010% P, 0.29% Si, 0.68% Mn; 0.18% C, 0.012% S, 0.019% P, 0.26% Si, 0.79% Mn

5.2.2

Special carbon steels

None

5.2.3

(4)

(1), (2), (3), (4)

Special stainless steels

Preheat and reboiler tubes: 304L stainless steel Preheat and reboiler and reclaimer tubes: 304L stainless steel Filter shells: 304 stainless steel

(1) (2), (3) (4)

31

32

5.2.4

Amine unit corrosion in refineries

Overlays, cladding and coating

None

5.2.5

(1), (2), (3), (4)

Stress-relieving policy

Yes

(1), (2), (3)

No policy

(4)

5.3

Operating parameters

5.3.1

Amine parameters and foaming Amine

Concentration (wt%)

Circulation (t h–1)

20 20–24 20–24 7

90 40 70 20

5.3.2

Foaming

Plant

0.075 kg t–1 0.042 kg t–1 0.042 kg t–1 5 t a–1

Rare or no Rare or no Rare or no No

(1) (2) (3) (4)

Acid gases, heat-stable amine salts, velocities and reboiler temperatures Acid gases

In rich amine

In lean amine

40 g l–1H2S 39 g l–1H2S 39 g l–1H2S Not clear

3 g l–1H2S 5 g l–1H2S 5 g l–1H2S Not clear

5.3.3

Loss

HSAS (wt%)

Velocity (ft s–1)

Reboiler temperature (∞C)

Plant

Not known Not known Not known No records

2.6 4.6 3.6 No records

130 125 125 107

(1) (2) (3) (4)

Make-up water

Demineralised water Condensate

5.3.4

(1), (2), (3) (4)

Solids present and filtration

Coke dust and precoat filter Mechanical filter of lean MEA

(1), (2), (3) (4)

Experiences of four plants using monoethanolamine

5.3.5

O2 leakage

No

5.3.6

(1), (2), (3), (4)

Inlet gas knock-out vessel

Yes

5.3.7

(1), (2), (3), (4)

Design factors

Yes

(1), (2), (3), (4)

5.4

Corrosion control

5.4.1

Treatments

None

5.4.2

(1), (2), (3), (4)

Monitoring

None

(1), (2), (3)

Monitoring of corrosion rates

5.4.3

(4)

Control parameters

None

(1), (2), (3)

Not known

5.5

33

(4)

Corrosion problems experienced

Regenerator: corrosion

(2), (3)

Regenerator overheads: thinning of walls in top air cooler

(4)

Regenerator reboiler: corrosion of shell

(3)

Lean–rich exchanger: corrosion of channels

(3)

No corrosion

(1)

34

Amine unit corrosion in refineries

6 Experiences of one plant using diisopropanolamine

6.1

Gas composition

92 vol% H2S, 3 vol% CO2, 4.5 vol% H2O, 0.3 vol% HC

6.2

Materials of construction

6.2.1

Carbon steels

ASTM A516Gr60; API 5LB, 0.17% C maximum, 0.01% S maximum, 0.02% P maximum, 1.3% Mn maximum, 0.41% Ceq maximum

6.2.2

Special carbon steels

Normalised steel + inclusion shape control UT BS5996LC4 for plate Maximum Vickers hardness, 235 HV (Brinell hardness, 225 HB) for base metal, heat-affected zone and weld for environments where H damage such as SCC, HIC or SOHIC might occur Temperature, <150 ∞C >50 ppm H2S in the aqueous phase and pH <5 >1000 ppm H2S and pH >5 Presence of cyanides, >20 ppm i.e. sour gas service piping, absorbers, rich amine solution piping, regenerator and regenerator overhead system

35

36

6.2.3

Amine unit corrosion in refineries

Special stainless steels

Some equipment internal structures such as column trays and AISI 410

6.2.4

Overlays, cladding and coating

None

6.2.5

Stress-relieving policy

According to inspections and laboratory investigations, for carbon steel susceptible to intergranular SCC in lean DIPA and to H damage in rich DIPA Stress relief for lean amine service piping including absorbers and regenerators (lean + rich)

6.3

Operating parameters

6.3.1

Amine parameters and foaming Amine

Concentration (% DIPA)

Circulation (m3 h–1)

23–27

300

6.3.2

Loss (t a–1)

Foaming

150 000–160 000

Not normally

Acid gases, heat-stable amine salts, velocity and reboiler temperature

Acid gases (wtppm H2S) ——————————————— In rich amine In lean amine

HSAS (wt%)

Velocity (m s–1)

Reboiler temperature (∞C)

ª20 000

0.69–0.81

Normally ª 1

122 maximum

6.3.3

600

Make-up water

Condensate: Fe concentration, 20–50 mg l–1; conductivity, <0.01 mmol l–1; oil, <0.5 mg l–1; pH ª 9

6.3.4

Solids present and filtration

>10 mm based on a Dahlman self-cleaning filtration system

Experiences of one plant using diisopropanolamine

6.3.5

37

O2 leakage

No

6.3.6

Inlet gas knock-out vessel

Yes

6.3.7

Design factors

Yes

6.4

Corrosion control

6.4.1

Treatments

None

6.4.2

Monitoring

None

6.4.3

Control parameters

Conductivity <10 000 mS m–1

6.5

Corrosion problems experienced

At the beginning of the 1980s, leaks discovered in the piping, leading to an extensive inspection, in which intergranular SCC was discovered in lean and rich amine; also HIC and hydrogen embrittlement occurred; now PWHT used in lean amine service and special carbon steels in sour or rich amine service

38

Amine unit corrosion in refineries