European Federation of Corrosion Publications

NUMBER 23

A Working Party Report on

CO2 Corrosion Control in Oil and Gas Production

Design Considerations

Edited by M. B. KERMANI & L. M. SMITH

Published for the European Federation of Corrosion by The Institute of Materials

THE INSTITUTE OF MATERIALS 1997

Book Number 688 Published in 1997 by The Institute of Materials 1 Carlton House Terrace, London SW1Y 5DB

1997 The Institute of Materials

All rights reserved

British Library Cataloguing in Publication Data Available on application

Library of Congress Cataloging in Publication Data Available on application

ISBN 1-86125-052-5

Neither the EFC nor The Institute of Materials is responsible for any views expressed

in this publication

Design and production by SPIRES Design Partnership

Made and printed in Great Britain

European Federation of Corrosion 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 corro- sion prevention.

Membership is based upon participation by corrosion societies and commit- tees 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, surface science, physico-chemical methods of measurement, the nuclear industry, computer based information systems, the oil and gas industry, the petrochemical industry and coatings. Working Parties 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 the 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 Soci6t6 de Chimie Industrielle in France, and The Institute of Materials in the United Kingdom. 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 other 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, for example, 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.

In 1987 the, then, Institute of Metals was appointed as the official EFC publisher. Although the arrangement is non-exclusive and other routes for publica- tion are still available, it is expected that the Working Parties of the EFC will use The Institute of Materials for publication of reports, proceedings etc. wherever possible.

The name of The Institute of Metals was changed to The Institute of Materials with effect from I January 1992.

A. D. Mercer EFC Series Editor, The Institute of Materials, London, UK

viii Series Introduction

EFC Secretariats are located at:

Dr B A Rickinson European Federation of Corrosion, The Institute of Materials, 1 Carlton House Terrace, London, SWIY 5DB, UK

Mr P Berge F6d6ration Europ6ene de la Corrosion, Soci6t6 de Chimie Industrielle, 28 rue Saint- Dominique, F-75007 Paris, FRANCE

Professor Dr G Kreysa Europ/iische F6deration Korrosion, DECHEMA e. V., Theodor-Heuss-Allee 25, D- 60486, Frankfurt, GERMANY

Preface

Corrosion is a natural potential hazard associated with oil and gas production and transportation facilities. This results from the fact that an aqueous phase is normally associated with the oil and/or gas. The inherent corrosivity of this aqueous phase is then dependent on the concentration of dissolved acidic gases and the water chemistry. The presence of H2S, CO 2, brine and/or condensed water with the hydrocarbon not only give rise to corrosion, but also can lead to environmental fracture assisted by enhanced uptake of hydrogen atoms into the steel. CO 2 is usually present inproduced fluids and, although it does not cause the catastrophic failure mode of cracking associated with H2S*, its presence can nevertheless result in very high corrosion rates particularly where the mode of attack on carbon and low alloy steels is localised. In fact CO 2 corrosion, or 'sweet corrosion', is by far the most prevalent form of attack encountered in oil and gas production and is a major source of concern in the application of carbon and low alloy steels. Hence, the need to have a document which systematically addresses the steps, considerations and parameters necessary to design oil and gas facilities with respect to CO 2 corrosion.

This document sets the scene on design considerations specifically related to CO 2 corrosion. It has been developed from feedback of operating experience, research results and operators' in-house studies. Particular attention has been given to the chemistry of the produced fluid, the fluid dynamics and physical variables which affect the performance of steels exposed to CO2-containing environments. The focus is on the use of carbon and low alloy steels as these are the principal construction materials used for the majority of facilities in oil and gas production offering economy, availability and strength.

This document is a practical, industry oriented guide on the subject for use by design engineers, operators and manufacturers. It incorporates much of the recent developments in the understanding of the ways in which detailed environmental and physical conditions affect the risk of CO 2 corrosion. It also describes means of corrosion control. It is comprehensive in addressing CO 2 corrosion of all major items of oilfield equipment and facilities incorporating, production, processing and transportation. As such, it provides a key reference for materials and corrosion engineers, product suppliers and manufacturers working in the oil and gas industry.

*'Sour corrosion', resulting from the presence of H2S, is the subject of EFC Publications Numbers 16 and 17.

Acknowledgements

The CO 2 Corrosion Work Group of the EFC Working Party on Corrosion in Oil and Gas Production held its first meeting in September 1993. Since then, several meetings have been held to address industry-wide issues related to engineering design for CO 2 corrosion. The organisation of the Work Group was undertaken by representatives from worldwide oil and gas producers, manufacturers, service companies and research institutions.

In achieving the primary objective, parameters affecting CO 2 corrosion, its mechanism and methods of control have been discussed during the Work Group meetings. These aspects form the core of the present document, Sections of which have been prepared by the Work Group members.

The chairmen of the Working Party and Work Group would like to thank all who have contributed their time and effort to ensure the successful completion of this document. In particular we wish to acknowledge a significant input from these individuals and their respective companies:

J Pattinson, A McMahon and D Harrop, BP, UK

J-L Crolet, Elf, France A Dugstadt, IFE, Norway

G Schmitt, MFI, Germany

Y Gunaltun, Total, France

E Wade, previously with Marathon, UK

O Strandmyr, Statoil, Norway

W Lang, Bechtel, UK

J Palmer, CAPCIS, UK M Swidzinski, Phillips, UK

M Celant, MaC, Italy

P O Gartland, CorrOcean, Norway

R S Treseder, CorrUPdate, USA

J Kolt, Conoco, USA

N Farmilo, AEA Technology, UK

In addition, valuable comments from R Connell and B Pots (Shell, The Netherlands) and T Gooch (TWI, UK) are appreciated.

Finally, one of the editors (MBK) wishes to thank BP for their support and permission to publish some of the information in this document.

Bijan Kermani Chairman of CO 2 Corrosion Group Workshop

Liane Smith Chairman of EFC Working Party on Corrosion in Oil and Gas Production

Contents

Ser ies In t roduct ion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . v i i

P re face . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . , . . . . . . . . . . . . . . . . ix

Acknowledgements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . x

1 Introduction ............................................................................................................... 1

2 Scope ........................................................................................................................... 3

3 The Mechan ism of CO2 Corrosion ........................................................................ 4

4 Types of CO2 Corrosion Damage .......................................................................... 6

4.1. Local ised Cor ros ion of Carbon Steel ............................................................... 6

4.2. Local ised Cor ros ion of Carbon Steel We lds ................................................... 7

5 Key Parameters Affect ing Corrosion .................................................................... 9

5.1. Water Wet t ing ..................................................................................................... 9

5.1.1. Water Character ist ics ................................................................................ 10

5.1.2. Hydrocarbon Character ist ics ................................................................... 10

5.1.3. Top-of - the-L ine Wet t ing ........................................................................... 11

5.2. Part ial P ressure and Fugac i ty of CO 2 ...................................................................................... 12

5.3. Temperature ...................................................................................................... 12

5.4. pH ....................................................................................................................... 14

5.5. Carbonate Scale ................................................................................................. 15

5.6. The Effect Of H2S ............................................................................................... 15

5.7. Wax Effect .......................................................................................................... 16

Prediction of the Severity of CO2 Corrosion .................................................... 18

6.1. CO 2 Cor ros ion Pred ict ion Mode ls For Carbon Steel ................................... 19

CO2 Corrosion Control .......................................................................................... 24

7.1. Micro-a l loy ing of Carbon and Low A l loy Steels ......................................... 24

7.1.1. Effect of Chromium ................................................................................... 24

7.1.2. Effect of Carbon ......................................................................................... 25

7.1.3. Effect of Other A l loy ing E lements .......................................................... 25

7.2. Effect of Glycol and Methano l ........................................................................ 26

vi Contents

7.3. pH Cont ro l ......................................................................................................... 27

7.3.1. The Role of pH ........................................................................................... 27

7.3.2. Wet Gas Transpor ta t ion Lines ................................................................. 27

7.3.3. Dif ferent Chemica ls and Their Mechan isms ......................................... 27

7.3.4. pH Mon i to r ing ........................................................................................... 28

7.4. Cor ros ion Inhib i t ion ......................................................................................... 28

7.4.1. Inhib i tor Mechan ism ................................................................................. 29

7.4.2. Inhib i tor Eff iciency and Inhib i tor Per fo rmance .................................... 30

7.4.3. Inhib i tor Par t i t ion ing and Pers is tency ................................................... 31

7.4.4. Commerc ia l Inhib i tor Packages ............................................................... 34

7.4.5. Inhib i tor Compat ib i l i ty ............................................................................. 34

7.4.6. Inhib i tor Dep loyment ............................................................................... 35

7.4.7. Inhib i tor D is t r ibut ion in Mu l t iphase P ipel ines ..................................... 36

7.4.8. Effect of F low on Inhib i t ion ..................................................................... 36

8 Cor ros ion A l lowance Determinat ion ................................................................. 37

8.1. Des ign Cor ros ion A l lowance .......................................................................... 38

8.1.1. Des ign Cor ros ion Rate .............................................................................. 38

8.1.2. Des ign Cor ros ion A l lowance Assessment ............................................ 38

9 Des ign Cons iderat ions .......................................................................................... 41

9.1 Wel l Complet ions .............................................................................................. 41

9.1.1. Cor ros ion Des ign ....................................................................................... 42

9.1.2. Cor ros ion Mon i to r ing ............................................................................... 43

9.2. P roduct ion Facil it ies ......................................................................................... 44

9.2.1. Cor ros ion Des ign ....................................................................................... 44

9.2.2. Mu l t iphase F lu id Behav iour .................................................................... 46

9.2.3. Cor ros ion Mon i to r ing ............................................................................... 47

9.3 Gas Reinject ion ................................................................................................... 49

9.3.1. Genera l Requ i rements for Gas Reinjection ............................................ 49

9.3.2. Onshore De l ivery Lines ............................................................................ 49

9.3.3. Offshore Del ivery Lines ............................................................................ 50

9.3.4. Injection Wel ls And Gas Lift Annu l i ...................................................... 50

References ............................................................................................................................ 51

European Federation of Corrosion 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 corro- sion prevention.

Membership is based upon participation by corrosion societies and commit- tees 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, surface science, physico-chemical methods of measurement, the nuclear industry, computer based information systems, the oil and gas industry, the petrochemical industry and coatings. Working Parties 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 the 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 Soci6t6 de Chimie Industrielle in France, and The Institute of Materials in the United Kingdom. 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 other 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, for example, 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.

In 1987 the, then, Institute of Metals was appointed as the official EFC publisher. Although the arrangement is non-exclusive and other routes for publica- tion are still available, it is expected that the Working Parties of the EFC will use The Institute of Materials for publication of reports, proceedings etc. wherever possible.

The name of The Institute of Metals was changed to The Institute of Materials with effect from I January 1992.

A. D. Mercer EFC Series Editor, The Institute of Materials, London, UK

viii Series Introduction

EFC Secretariats are located at:

Dr B A Rickinson European Federation of Corrosion, The Institute of Materials, 1 Carlton House Terrace, London, SWIY 5DB, UK

Mr P Berge F6d6ration Europ6ene de la Corrosion, Soci6t6 de Chimie Industrielle, 28 rue Saint- Dominique, F-75007 Paris, FRANCE

Professor Dr G Kreysa Europ/iische F6deration Korrosion, DECHEMA e. V., Theodor-Heuss-Allee 25, D- 60486, Frankfurt, GERMANY

1 Introduction

CO 2 corrosion has been a recognised problem in oil and gas production and transportation facilities for many years. Despite systematic attempts to analyse it and develop predictive models, it is still not a fully understood phenomenon and there remains ambiguity and argument on the engineering implications of parameters which affect it. Furthermore, most of the present predictive models are not based on adequate information to take into account the increasingly harsh environments seen in deep wells and they also take little account of hydrodynamic parameters, and so often lead to conservative designs.

The problem cannot be said to be a diminishing one, since reliable prediction of the life of carbon steel components in production systems remains unclear [1], particularly, in the current situation where oil and gas exploration activities have moved to more marginal areas and harsher operational conditions. Many of these fields necessitate the transportation of raw wellhead gas and fluids either from wells (sometimes subsea) or from remote areas to a central processing facility, with the export of treated fluids to a distant terminal/additional processing facility. Although such systems have often been designed to operate successfully with corrosion inhibition, there have been instances where this approach has failed in practice. Nevertheless, with detailed evaluation of the corrosion risk, combined with a proper corrosion management programme (control, monitoring, inspection and assessment), production and transportation of wet hydrocarbon gas and oil in carbon steel facilities is considered technically viable.

In brief, where there is a risk of internal corrosion in wet production facilities there is a need for:

A design methodology for reviewing the potential corrosion risks and developing a suitable design and corrosion allowance where appropriate. This is the principal subject of this document.

An inhibitor deployment programme including why inhibitors are used, how they are selected and how to achieve maximum performance in the field to alleviate internal corrosion of facilities.

A corrosion control management programme which, based on the design review, details the procedures for corrosion control, how such corrosion is to be monitored and how the facilities are to be inspected

A defect assessment methodology which determines whether the integrity of the facility is compromised or likely to be compromised, in the event that a corrosion defect is detected.

CO 2 Corrosion Control in Oil and Gas Production--Design Considerations

In this document, the emphasis has been placed primarily on the first point and the other three points have been addressed briefly.

The first step in establishing the design methodology is an understanding of CO 2 corrosion. This requires a multi-disciplinary approach, involving knowledge of fluid chemistry, hydrodynamics, metallurgy and inhibitor performance and partitioning. Mechanistic understanding of the phenomenon is essential to enable development of engineering criteria for accurate prediction of the form and rate of corrosion which may occur. This document aims to address these issues.

2 Scope

This document sets out a proposed design philosophy for the production and pipeline transportation of wet oil, wet gas and multiphase fluids, for use in the technical/ commercial assessment of new field developments and in prospect evaluations. For the purpose of this document, wet oil, wet gas and multiphase fluids are defined as oil and/or gas containing water and CO2.

The mechanism of CO 2 corrosion is explained and the forms that the corrosion damage can take are described in Section 3. This is followed by a description of the forms of CO 2 corrosion damage and the steps necessary to minimise localised corrosion of carbon steel welds (Section 4).

The key parameters influencing the rate of CO 2 corrosion are discussed in Section 5. An understanding of the role of the carbonate scale in influencing the form of the corrosion is shown to be important in understanding how some inhibitors operate and how the nature of the scale changes with temperature. This leads to Section 6 which describes a summary of the models available for predicting the corrosion rate and the parameters they incorporate.

Section 7 deals with various methods of corrosion control, including the addition of minor alloying elements and changing the corrosive environment through the addition of pH controller, glycols or corrosion inhibitors.

In considering the application of this knowledge on forms of corrosion damage and approaches to corrosion rate prediction and mitigation to the question of facilities design, the first issue is to establish an appropriate corrosion allowance. This is dealt with in Section 8.

The document then highlights parameters which are significant to different items within the production facilities. For the purposes of discussing corrosion design, Section 9 has been divided into:

Well Completions;

Production Facilities (including flowlines and pipelines); and

Gas Reinjection Systems.

Finally, some comments are given on corrosion monitoring appropriate to the different facilities.

3 The Mechanism of CO 2 Corrosion

The problem of CO 2 corrosion has long been recognised and has prompted extensive studies. Dry CO 2 gas is not itself corrosive at the temperatures encountered within oil and gas production systems, but is so when dissolved in an aqueous phase through which it can promote an electrochemical reaction between steel and the contacting aqueous phase. CO 2 is extremely soluble in water and brines but it should also be remembered that it has even greater solubility in hydrocarbons m potentially 3:1 in favour of the hydrocarbon. Hydrocarbon fluids are generally produced in association with an aqueous phase. In many cases the hydrocarbon reservoir will also contain a significant proportion of CO 2. As a result of this, CO 2 will dissolve in the aqueous phase associated with hydrocarbon production. This aqueous phase will corrode carbon steel.

Various mechanisms have been postulated for the corrosion process but all involve either carbonic acid or the bicarbonate ion formed on dissolution of CO 2 in water this leads to rates of corrosion greater than those expected from corrosion in strong acids at the same pH. CO 2 dissolves in water to give carbonic acid, a weak acid compared to mineral acids as it does not fully dissociate. The steps of carbonic acid reaction may be outlined as follows:

CO2(g ) 4- H20 ---> CO2(dissolved) (1)

CO2(dissolved) 4- H20 =) H2CO 3 ~ H + HCO 3- (2)

The mechanism postulated by de Waard [2-4] is, perhaps, the best known:

H2CO 3 + e- --9 H + HCO 3- (3)

2 H --~ H 2 (4)

with the steel reacting:

Fe --9 Fe 2+ + 2e- (5)

and overall:

CO 2 + H20 + Fe --~ FeCO 3 (iron carbonate) + H 2 (6)

Whilst there is some debate about the mechanism of CO 2 corrosion in terms of which dissolved species are involved in the corrosion reaction, it is evident that the

The Mechanism of CO 2 Corrosion

resulting corrosion rate is dependent on the partial pressure of CO 2 gas. This will determine the solution pH and the concentration of dissolved species.

In reality, the complete chain of electrochemical reactions is much more complex than this brief outline. Depending upon which is the rate determining step the dependance of the electrochemical reactions on pH and dissolved CO 2 varies.

4

Types of CO 2 Corrosion Damage

CO 2 corrosion may manifest itself as general thinning or localised attack. Localised corrosion is characterised by loss of metal at discrete areas of the surface with surrounding areas remaining essentially unaffected or subject to general corrosion. These discrete areas may take various geometrical shapes. Thus, circular depressions usually with tapered and smooth sides are described as pits. Stepped depressions with a flat bottom and vertical sides are referred to as mesa attack. Other geometrical forms of localised corrosion include slits (sometimes referred to as knife line), grooves etc. In flowing conditions localised attack may take the form of parallel grooves extending in the flow direction; this phenomenon is known as flow induced localised corrosion.

4.1. Localised Corrosion of Carbon Steel

CO 2 corrosion can appear in three principal forms, pitting, mesa attack or flow induced localised corrosion.

Pitting can occur over the full range of operating temperatures under stagnant to moderate flow conditions. The susceptibility to pitting increases and time for pitting to occur decreases with increasing temperature and increasing CO 2 partial pressure. Depending on the alloy composition there exists a temperature range with a maximum susceptibility for pitting [5].

Inspections of sweet gas wells have indicated that localised corrosion, including pitting, often occurs preferentially at certain depths (i.e. in certain temperature ranges). Generally 80-90C is a temperature range where pitting is likely to occur in sweet gas wells. Pitting may arise close to the dew point temperature and can relate to condensing conditions. There are no simple rules for predicting the susceptibility of steels to pitting corrosion.

Mesa type attack is a form of localised CO 2 corrosion under medium flow conditions [6]. In such attack, corrosion results in large flat bottomed localised damage with sharp steps at the edges. Corrosion damage at these locations is well in excess of the surrounding areas.

The conditions most likely to lead to mesa attack are those under which carbonate films can form but are not strongly stable. Film formation begins around 60C and thus mesa attack is much less of a concern at temperatures below this. If the general filming conditions are borderline then local variations in flow or metallurgy or both may be enough to de-stabilise films. This type of localised attack results from local spalling of carbonate scales after reaching a critical scale thickness [7-9]. This local spalling occurs due to intrinsic growth stresses in the scale [10]. Spalling of the scale exposes underlying metal which then corrodes and may reform surface scale. On regaining a critical thickness the newly formed scale can crack and spall again producing another step.

Types of CO 2 Corrosion Damage

Spalling of scale particles or flakes relieves the stress in the scale adjacent to and around the spalled area. Therefore, this scale remains attached to the surface and can protect it from localised attack. As a result, the flat bottomed pits obtain sharp edges. Mesa attack may also simply result from self sustaining galvanic coupling between protective and non-protective corrosion films.

Flow induced localised corrosion (FILC) in CO 2 corrosion starts from pits and/ or sites of mesa attack above critical flow intensities. The localised attack propagates by local turbulence created by the pits and steps at the mesa attack which act as flow disturbances. The local turbulence combined with the stresses inherent in the scale may destroy existing scales. The flow conditions may then prevent re-formation of protective scale on the exposed metal.

4.2. Localised Corrosion of Carbon Steel Welds

Localised corrosion of carbon steel welds in CO 2 corrosion systems has been experienced by many operators. It is a complex problem because it is dependent partly on the environment (and the nature of any carbonate scale formed), partly on the metallurgy and composition of the carbon steel and the weld and partly on the geometry of the weld profile (local turbulence).

Initially, preferential attack may arise from galvanic differences across a weld due to compositional or microstructural differences between the deposited weld metal, the parent steel and file heat affected zone (HAZ).

The location and morphology of the preferential corrosion is influenced by a complex interaction of many parameters including the environment, the operating conditions, the parent ,;teel composition, the deposited weld composition, the welding procedure and the initial surface state. Changes in any one of these parameters can cause a significant difference in the weldment corrosion behaviour.

Changing the composition of the weld metal relative to the parent steel can make the weld metal more, or less, susceptible to preferential attack. Similarly, changing the grade of parent steel can affect the behaviour of the weld metal but, in conjunction with the welding procedure, the parent steel composition will also determine the microstructure of the HAZ and therefore influence the susceptibility to preferential attack in that region.

The welding procedure will directly influence the HAZ microstructure, but will also affect the degree of dilution of the weld metal by the parent steel and the composition at the fusion line of the weld. The presence of welding slags, oxide films and inclusions increase the complexity of the weld corrosion phenomenon.

It is extremely important to note that a weld consumable selected to avoid preferential corrosion in one environment could exacerbate the problem in another. For example, consumables containing 1% Ni or 0.6% Ni plus 0.4% Cu as recommended for seawater injection systems may cause problems if used under certain conditions in sweet hydrocarbon environments [11]. Rapid corrosion of the weld metal has occurred in some instances while HAZ attack has also been observed. The window of conditions under which this problem occurs has yet to be accurately defined. However, in the majority of cases, failures have occurred at temperatures approaching conditions under which protective scales are expected to form (70-80C).

CO 2 Corrosion Control in Oil and Gas Production reDesign Considerations

The risk of preferential weld corrosion can be minimised by conducting laboratory tests on the relevant weldment under simulated service conditions using appropriate electrochemical monitoring techniques, including galvanic coupling through zero resistance ammeters. It should be noted that although laboratory studies have generally been successful in simulating weld corrosion problems in other situations than CO 2 corrosion service, in some instances (such as with higher nickel contents) cathodic weld metal behaviour has been observed in the laboratory, but anodic behaviour in service, which may be due to the difference in the initial surface state.

Weldment corrosion behaviour must, therefore, be confirmed by monitoring in service. The same monitoring techniques can be used, ideally in combination with other techniques such as ultrasonic wall thickness measurements.

The effects of inhibition (and biocide treatments) on weldment corrosion must also be considered. Although inhibition can be an effective means of controlling preferential weld corrosion, inhibitor adsorption can be influenced by weld metal composition and, in some cases, protection is not achieved. Again, inhibitor tests on weldments under simulated service conditions can be used to select an appropriate inhibitor formulation.

The theory of why the scale breaks down at the weld is a combination of:

Local turbulence because the weld root protrusion disturbs the flow and eddys then break up the scale.

The chemistry of the weld is slightly different from the adjacent metal and for some reason (e.g. carbide structure) the scale is not as protective.

Solving the problem is not easy. Steps which can be taken include:

Specifying a maximum root penetration of 0.5 mm.

Using filler metals for the root run with alloying additions of copper and nickel (e.g. ISO:E51 4 B 120 20 (H) AWS:E7018-G) typically used for welding so-called weathering steels. Low weld silicon contents are also suggested, probably < 0.35%, since a few practical problems have been experienced in the past with weld Si contents of around 0.5% or more. A problem with Si is that recovery across the arc depends upon the arc length and the local shielding (i.e. on the joint design, welding position etc.). Thus, the same electrode can give an appreciable range of Si in the weld deposit with different welders or joint geometry. However, < 0.35%Si should generally be achievable.

Detailed laboratory testing simulating flowing conditions to select the correct combination of filler and inhibitor for the given conditions. (Testing is particularly recommended for operations above 70C).

5 Key Parameters Affecting Corrosion

CO 2 corrosion is affected by a number of factors including environmental , metallurgical and hydrodynamic parameters. These are described in this Section.

5.1. Water Wetting

For CO 2 corrosion to occur there must be water present and it must wet the steel surface. The severity of CO 2 corrosion attack is proportional to the time during which the steel surface is wetted by the water phase. Consequently the water cut is an important parameter. However, the influence of the water cut on the corrosion rate cannot be separated from the flow velocity and the flow regime effects. In oi l /water systems emulsions can form. If a water-in-oil emulsion is formed then the water may be held in the emulsion and water wetting of the pipewall prevented or greatly reduced leading to a consequential reduction in the rate of corrosion. If, on the other hand, an oil-in-water emulsion is formed, then water wetting of the pipewall will occur. The transition from a water-in-oil emulsion to an oil-in-water emulsion occurs around 30 to 40 wt% water in oil and, in straight pipe with emulsified liquids, a clear jump in the corrosion rate can be demonstrated [12]. This had lead to a rule-of-thumb that corrosion is greatly reduced for water cuts below around 30 wt% water cut in a crude oil line.

However, the 30 wt% rule-of-thumb is only valid if an emulsion is formed and no water drops out along the line. This is a stringent criterion and is not usually met in flowlines and export lines. Operators' experience in systems such as Forties is that water drop out can occur at very low water cuts (ie less that 5 wt%) and that emulsions cannot be relied on for corrosion control. Thus, the 30 wt% rule-of-thumb is not normally recommended and analysis of corrosion risk should assume that water drop-out will occur at some point in the line.

Principal factors influencing water wetting include:

Oi l /water ratio;

Flow rate and regime;

Surface condition (roughness, cleanliness);

Water drop-out (low spots);

Water shedding due to changing flow profile (bends, welds); and

3 rd party entries (mixing effect).

10 CO 2 Corrosion Control in Oil and Gas Production--Design Considerations

5.1.1. Water Characteristics

The water associated with oil and gas production arises from two principle sources:

As 'Condensed Water'; this water is formed by the condensation of water vapour from the gas phase.

As 'Reservoir Water'; this is reservoir (or formation) brine entrained with the main hydrocarbon well stream fluids.

Reservoir water contains a wide range of dissolved salts which can influence the pH of the wet CO2-containing hydrocarbon system. Bicarbonates can be particularly beneficial as they can usefully increase system pH rendering the CO2-bearing liquids potentially less harmful.

Further information on water characteristics is given in EFC Publication Number 17.

5.1.2. Hydrocarbon Characteristics

Crude oils can successfully entrap water to form stable water-in-oil emulsions. Significant levels of water can be effectively held up in this manner thereby preventing the water from wetting and corroding the steel. Depending on the water content and other variables an oil-in-water emulsion can form, resulting in water wetting of the steel.

The ability of crude oils to form stable emulsions will depend on oil chemistry, specific gravity, viscosity, velocity and system pressure, temperature and flow conditions. In general it has been found that most crude oils can incorporate water up to at about 20 vol.% as long as the liquid flow velocity is above a critical level [13]. For any particular pipe diameter the critical velocity for water uptake by flowing crude oil can be predicted after the method proposed by Wicks and Fraser [14]. Typically this critical velocity is around 1 ms -1 for most crude oils or as low as 0.5 ms -1 in deviated wells where temperature has a major influence.

In practice the emulsion forming capability of the crude oils of interest should be determined experimentally to establish the actual amount of water that can be held in an oil-based emulsion.

Lighter hydrocarbon condensates (e.g. NGLs) do not hold up water as effectively as crude oils. The emulsions that are formed are weak and can break down rapidly resulting in water wetting.

The corrosion problems in the oil lines and deviated oil wells with stratified flow regime are well established (water line corrosion). At velocities below the critical velocity for water/oil separation, the flow regime is generally of the segregated type. The steel surface is almost permanently wetted by the water phase even for the water cuts as low as 1%. Corrosion products and other solid particles coming from the reservoir accumulate in the water phase at the lower side of the line or tubing and may erode the corrosion product scale on the steel.

Some field results show that the water/condensate or oil/water separation is possible even in slug flow where the flowing gas pushes the separated condensate/ oil phase above the water phase [15]. The water phase may remain at low spots until

Key Parameters Affecting Corrosion 11

its volume becomes large enough to disturb the gas flow. Consequently full water wetting may occur even in slug flow and with very low water cuts.

For the design of new installations, the evaluation of the flow regime, based on the estimated development of the production rates during the field life, is of a paramount importance. Whatever the water cut is, the line or tubing diameter should ideally be selected in order to prevent segregated flow.

It is also important to consider the impact of production/process chemical treatments on crude oil emulsion stability. Emulsion breakers are often introduced into production facilities to enhance water/oil separation. It is not unusual for these to carry through with the separated liquid hydrocarbon stream if they are used in excess. The carry through of such treatment chemicals to later parts of the plant will influence the ability of the crude oil to entrain and retain water as a stable emulsion through the production facilities.

The separation of water from crude oils (with or without added de-emulsifiers) may occur even at very low water cuts (e.g. less than 5%) at low points in a pipeline. Consequently, for pipeline corrosion control a regular pipeline pigging campaign may be required to ensure that any separated water accumulations are effectively removed, particularly as flow rates decrease towards the end of the field life.

5.1.3. Top-of-the-Line Wetting

In gas/condensate pipelines the corrosion rate may vary between the top and the bottom of the pipe. Under stratified flow regimes, the top-of-line (TOL) location in a pipeline is not continually water wetted. However, there is always some condensation of water on the inner pipe wall. If this water is rapidly saturated with corrosion products, the pH in the water increases and causes the formation of fairly protective corrosion product films on the steel surface which can reduce the corrosion rate. A constant corrosion rate is obtained when the corrosion rate has been reduced so much that it is balanced by the rate at which corrosion products are transported away from the surface by the condensed water. (At high condensation rates the water may be undersaturated and remain acidic and corrosive).

Experiments at IFE showed that the corrosion rate could be calculated when the condensation rate and the solubility of iron carbonate in the condensed water are known, and a simple model was developed [16]. At moderate condensing rates (< 0.25 gm-2s -1) the corrosion rate will be less than 0.1 ram/year over a wide range of CO 2 partial pressures (0-12 bars) and temperatures (20-100C).

It is also possible to calculate the TOL corrosion rate using the Shell corrosion rate prediction model as a condensation factor is included [3]. The factor Fcond is equal to 1 for high condensation rates (= 2.5 g m-2s -1) and is reduced to Fcond = 0.1 when the condensation rate is less than 0.25 gm-2s -1. The factor is regarded as conservative.

Excessive corrosion rates can be mitigated by reducing the cooling rate of the pipe wall and by avoiding cold spots. Under practical conditions, at low cooling and condensing rates, it seems to be generally accepted that no serious corrosion problems have been experienced in gas pipelines with CO 2 only, but that traces of H2S have led to some attack in a few cases (in these cases the buffering by corrosion products is lowered by the lower solubility of iron sulfides). Nevertheless, TOL corrosion can

12 CO 2 Corrosion Control in Oil and Gas Production--Design Considerations

be difficult to control with a reasonable degree of certainty, since injected chemicals can not in general be expected to be present in the condensing water.

5.2. Partial Pressure and Fugacity of CO 2

CO 2 corrosion results from the reaction of a steel surface with carbonic acid arising from the solution of CO 2 in an aqueous phase m i.e. it is not a direct reaction with gaseous CO 2. The concentration of CO 2 in the aqueous phase is directly related to the partial pressure of CO 2 in the gas in equilibrium with the aqueous phase. Thus in CO 2 corrosion, estimates of corrosion rate are based on the partial pressure of CO 2 in the gas phase.

It should be noted that if there is no free gas present then the CO 2 content of the water will be determined by the PCO2 of the last gas phase in contact with the fluids (e.g. the PCO2 at the bubble point for well bore fluids; the PCO2 in the low pressure separator gas for fluids in an export pipeline).

Strictly, it is the thermodynamic activity of the CO 2 in the aqueous phase that will be important in the corrosion reaction rather than its concentration per se. This activity will vary with concentration depending on the chemical composition of the aqueous phase. However, the activity of the CO 2 in the aqueous phase is directly linked to the activity in the gas phase, known as the fugacity. The fugacity of a gas is effectively the activity of the gas and for ideal gases, this is equal to the partial pressure.

However, with increasing pressure the non-ideality of the natural gas will play an increasing role, and instead of the CO 2 partial pressure, the CO 2 fugacity fc02 should be used with some models:

f co 2 = f'Pco2 (7)

where f is the fugacity coefficient. Figure 1 provides a conservative estimate for f. The presence of other gases will generally further reduce the fugacity coefficient. When necessary, the fugacity should certainly be taken into account in any predictive model for system pressures exceeding 100 bar.

However, it is important to keep a consistent approach for both gas and water phases. If there is insufficient information to establish the non-ideality in the aqueous phase, then Pco2 should be used in considering the gas phase. This is particularly true for pH calculation.

5.3. Temperature

The corrosion of carbon and low alloy steels in a wet CO 2 environment can lead to iron carbonate as a reaction product. Although recent work suggests that an iron carbide matrix may be first exposed on the surface of corroding steel, a carbonate scale which may protect the underlying metal can often be formed [17]. The formation and protectiveness of such a scale depends on a number of factors that are described in Section 5.5.

Key Parameters Affecting Corrosion

O

U_

0.9

0.8

0.7

0.6

0.5

0.4

------..44o 120 ~

,

40 " ~ ~

0 50 1 O0 150 200

o C

Total system pressure, bar

Fig. 1 Fugacity coefficient for CO 2 in methane for gas mixtures with less than 5 mole% CO 2 [4].

13

However, at higher temperatures (e.g. around 80C) the iron carbonate solubility is decreased to such an extent that scale formation is more likely. Under laboratory conditions, rates of uniform corrosion are consistently reduced at higher temperatures.

Some laboratory studies show that the initial rate of uniform corrosion increases up to 70-90C, probably due to the increase of mass transfer and charge transfer rates [2,3]. Above these temperatures, the corrosion rate starts to decrease. This is attributed to the formation of a more protective scale due to a decrease in the iron carbonate solubility and also to the competition between the mass transfer and corrosion rates. As a result, a diffusion process becomes the rate determining step for the corrosion rate.

Field evidence for a maximum temperature for CO 2 corrosion has been found in some wells. These case histories show that in oil and gas wells maximum corrosion takes place where the temperature is between about 60 and 100C [2,18,19] which may coincide with dew point temperature in gas wells. In these cases, below 60-70-C, the corrosion rate increased with increasing temperature and above 80-100C the corrosion rate decreased with increasing temperature. Conversely, very high corrosion rates have been observed up to 130C at the top of some gas wells exascerbated by high rates of water condensation.

14 CO 2 Corrosion Control in Oil and Gas Production reDesign Considerations

5.4. pH

The pH value is an important parameter in corrosion of carbon and low alloy steels. The pH affects both the electrochemical reactions and the precipitation of corrosion products and other scales. Under certain production conditions the associated aqueous phase can contain salts which will buffer the pH. This tends to decrease the corrosion rate and lead to conditions under which the precipitation of a protective film or scale is more likely.

For bare metal surfaces which are representative for worst case corrosion, laboratory experiments indicate that a flow sensitive H + reduction dominates the cathodic reaction at low pH (pH < 4.5) while the amount of dissolved CO 2 controls the cathodic reaction rate at higher pH (pH > 5).

In addition to the effects on the cathodic and the anodic reaction rates, pH has a dominant effect on the formation of corrosion films due to its effect on the solubility of ferrous carbonate, as illustrated in Fig. 2. It is seen that the solubility of corrosion products released during the corrosion process is reduced by just five times when the pH is increased from 4 to 5 but by a hundred times with an increase from 5 to 6. The lower solubility gives a much higher FeCO 3 supersaturation on the steel surface and a subsequent acceleration in precipitation and deposition of iron carbonate scale [17]. The likelihood of protective film formation is therefore increased significantly when the pH is increased beyond 5 and this can explain why low corrosion rates have been reported for many fields where the pH is in the range 5.5--6. However, the solubility of FeCO 3 must not be confused with that of ferrous ions (Fe2+).

(p LI_

E C).. C~.

o~ o~ ..O

0

cO

o o Q)

Li .

100

10-

1 -

0.1 m

0.01 -

0.001 I I 5 6

pH

Fig.2 Solubility of iron carbonate released during the corrosion process at 2 bar CO 2 partial pressure and 40 C [17].

Key Parameters Affecting Corrosion

5.5. Carbonate Scale

15

Reliance on carbonate scales/film as described in section 5.3 to give continuous protection is not totally warranted. In particular, in regions of high flow or at welds, scale breakdown can lead to rapid rates of localised corrosion ('mesa attack').

Recent extensive work on the subject has shown that the corrosion process involves the initial production of an iron carbide matrix on the surface of corroding steel. Corrosion product film of FeCO 3 or Fe30 4 will then form as a scale on the surface resulting in a reduction in the corrosion rate [20]. The formation and protectiveness of such a scale depends on a number of factors such as the solubility of iron carbonate (which will vary with pH and the presence of other salts), the rate of reaction of the underlying steel and the surface condition (roughness/cleanliness/prior corrosion).

The scale [9] may be weakened by high chloride concentrations, by the presence of organic acids or it can be eroded by high speed liquids. Practical velocities for smooth flow in systems with single phase liquid flow are often too low to achieve this; only the impact of high speed liquid droplets can damage the scale. The occurrence of such a disturbed flow pattern in practical systems can be predicted from the suggestion made by Smart [21] that the onset of erosion-corrosion is coincident with the transition to the annular mist flow regime in multiphase flow. With the superficial liquid velocities associated with wet gas transport, this transition arises at superficial gas velocities between 15 and 20 ms -1. Above these velocities the scale protectiveness may be impaired.

The effects of short term scaling will often make interpretation of short-term laboratory experiments difficult and for this reason such data must be treated with care m especially results that give unexpectedly low rates of corrosion.

5.6. The Effect of H2S

Leaving aside the cracking and corrosion problems associated with sour service, H2S can have a beneficial effect on wet hydrocarbon CO 2 corrosion as sulfide scales can give protection to the underlying steel. The effect is not quantified but it does mean that facilities exposed to gas containing low levels of H2S may often corrode at a lower rate than completely sweet systems in which the temperatures and CO 2 partial pressures are similar.

The acid formed by the dissolution of hydrogen sulfide is about 3 times weaker than carbonic acid but H2S gas is about 3 times more soluble than CO 2 gas. As a result, the contributions of CO 2 and H2S partial pressures to pH lowering are basically similar. H2S may cause corrosion also in neutral solutions, with a uniform corrosion rate which is generally very low [22]. Furthermore, H2S may play an important role in the type and mechanical resistance of corrosion product films, increasing or decreasing their strength.

Many papers have been published on the interaction of H2S with low carbon steels under ambient conditions and the work relating to H2S corrosion problems in the oil and gas industry is well documented. However, literature data on the interaction of H2S and CO 2 is still limited. The nature of the interaction of H2S and CO 2 with carbon

16 CO 2 Corrosion Control in Oil and Gas Production ~Design Considerations

steel is complex. From past experience corrosion product layers formed on mild steel can be protective or can lead to rapid failure depending on the production conditions. This is primarily because an iron sulfide (FeS) film will form if H2S is predominant and iron carbonate (FeCO 3) will form if CO 2 is predominant in the gas.

The majority of the open literature does indicate that the CO 2 corrosion rate is reduced in the presence of H2S at ambient temperatures. However, it must be emphasised that H2S may also form non-protective layers [23], and that it catalyses the anodic dissolution of bare steel [24]. There is a concern that steels may experience some form of localised corrosion, but very little information is available.

Published laboratory work has not been conclusive, indicating that there is a need to carry out further study in order to clarify the mechanism [25,26]. A recent failure showed how the corrosion rate in the presence of a high concentration of H2S may be higher than predicted using CO 2 corrosion prediction models [27]. However, in spite of the work on H2S corrosion of steels, no equations or models are available to predict corrosion as is the case for CO 2 corrosion of steels.

Cracking of metals in production environments containing H2S is a major risk. Hydrogen sufide can cause cracking of carbon and low alloy steels within certain conditions of H2S partial pressure, pH, temperature, stress level and steel metallurgy and mechanical properties (e.g. hardness). The type of damage manifests itself in the form of cracking such as sufide stress cracking (SSC), stepwise cracking and other forms of damage which are discussed at greater length in EFC Publication No. 16.

5.7. Wax Effect

The presence of wax in main oil lines can influence CO 2 corrosion damage in two ways; exacerbating the damage or retarding it, the effects depending on other operational parameters such as temperature, flow, etc. and uniformity and the nature of the wax layer.

Field experience in sweet oil lines in the USA, have shown that a layer of wax (paraffin) deposited on a carbon steel surface can result in severe pitting of the steel in anaerobic aqueous solutions of carbon dioxide [28]. Severe pitting occurred along the bottom of the pipe. Pitting (small random pits) tended to concentrate at the start of an uphill run where water could collect. Scale analysis showed the presence of iron sulfide. This was attributed to the presence of bacteria. (The detection of sulfide in a sweet oil line is not usual. In fact in the case of microbially assisted corrosion, scale analyses often show 15-30% Fe S. ). Velocity was an apparent factor affecting x y the location of pits; there being a decrease in the number of pits at flow velocities above about 0.6 ms -1. (The principal practical observation was that conventional commercial corrosion inhibitors were ineffective in controlling corrosion; the corrosion control measure finally adopted for the gathering lines was to install pull-through polyvinyl chloride liners). In this case the proposed corrosion mechanism is of diffusion of carbon dioxide through the wax layer which is thought to provide a large cathodic area that supports anodic dissolution of the steel at discontinuities of the wax layer. The effect was reproduced in laboratory tests with paraffin coated specimens exposed to CO 2 saturated water at atmospheric pressure and ambient

Key Parameters Affecting Corrosion 17

temperature. Localised corrosion only took place where there was no wax deposit. The areas covered with wax were protected from the CO 2 containing solution. The difficulty in controlling this type of localised corrosion with commercial oilfield inhibitors was demonstrated in these laboratory tests [28].

In contrast, field experience of a 20 in. (50.8 cm) oil line in Indonesia (about 20 km length) showed almost nil corrosion rate during about 10 years service which was attributed to a wax deposit on the pipe wall. The water cut was up to 50%. Internal corrosion started when light hydrocarbon condensate produced from a gas field was injected into the line. This dissolved the wax deposit exposing the steel surface, as confirmed by internal inspection of a corroded pipe section.

6 Prediction of the Severity of CO 2 Corrosion

It is apparent that CO 2 corrosion of carbon and low alloy steels has been, and remains, a major cause of corrosion damage in oil and gas field operations [1]. The industry relies heavily on the extensive use of these materials, and thus there is a desire to predict the corrosivity of CO2-containing brines when designing production equipment and transportation facilities.

A true industry standard approach to predicting CO 2 corrosion does not exist although there are aspects of commonality between the approaches/models offered by a number of operators, research organisations and academic establishments. Apart from limited reference in National Gasoline Association of America [29] and American Petroleum Institute [30] publications, there is no professional body or agency to provide a standard guideline on CO 2 corrosion prediction. However, in particular, the work of Shell in this area has provided a reference point. The Shell (de Waard et al.) equation or nomogram has been developed as an engineering tool. It presents, in a simple form, the relationship between potential corrosivity (worst case) of aqueous media for a given level of dissolved CO 2, defined by its partial pressure, at any given temperature. The relative simplicity of the Shell approach and its ease of use have undoubtedly been positive factors in its broad acceptance. This is in contrast to the arguably more 'all-encompassing' models of, for example, Southwestern Louisiana, VERITEC, CAPCIS and others which require more detailed input data to run them. Also input of inspection/monitoring data may be called for to refine the models' accuracy or field/well specificity.

There would appear to be a trade-off between a model's relative ease of use versus availability, detail and reliability/accuracy of necessary input data/conditions combined with the degree of accuracy/absoluteness required in the assessment of the corrosion risk. The last will also be influenced by the ease and sensitivity of subsequent corrosion monitoring and inspection.

There still remains an absence of any strong systematic correlation between predicted and actual field corrosion rates and experience, although CORMED goes someway in this respect [31]. Future development of predictive models should contain a much stronger element of field correlation.

The engineer ideally wants a predictive tool that can be readily applied and is suitable for application at all stages of project development and subsequent operation. This may seem a tall order but it may nevertheless be argued that the fundamentals of the CO 2 corrosion process will be common to all situations; It is the overlying effects of such factors as flow regime, film formation/deposition, hydrocarbon phase and corrosion inhibitor which cloud or complicate the picture. Both the Shell and CORMED models have been developed from a basic consideration of the CO 2 corrosion reactions, the former more empirical in origin and the latter more theoretical. Both have then attempted to account for the overlying effects either by applying correction factors (Shell) or through field correlation (CORMED).

Prediction of the Severity of CO 2 Corrosion 19

Notwithstanding the above discussion, the intent of the present document was not to provide or recommend a particular corrosion prediction tool, but leave the decision to the individuals. Nevertheless, this section provides an overview of CO 2 corrosion models and parameters considered in each model. Furthermore, the parameters which are considered essential in designing for CO 2 corrosion and are therefore needed, no matter which predictive tool is used, are presented in Fig. 3.

Based on the foregoing discussion, the procedure for predicting CO 2 corrosion damage is described in Fig. 4. A key feature is the positive and ongoing interaction between the corrosion engineer and petroleum engineer to ensure that relevant service conditions are defined and detailed. There has to be a common understanding of what is required against the limitations of the selected predictive model and subsequent monitoring/inspection. A case is made for rationalising monitoring and inspection data with predicted rates, to strengthen the relevance and validity of the latter, whilst working to introduce a stronger predictive element to the former.

Figure 5 summarises the necessary overall critical steps identified in working to define a risk of CO 2 corrosion. It should also be recognised that characterising the flow regime/shear stress to establish water wetting (Section 5.1) may also be critical to achieving effective corrosion inhibitor selection and deployment (Section 7.4).

6.1. CO 2 Corrosion Prediction Models For Carbon Steel

Different oil companies and research institutions have developed a large number of prediction models. Table 1 (p.22) gives an overview of the parameters treated in

To Hydrodynamics: ~ [ Local/bulk flow regimes |

p of line/Bottom of line J Acid(H2s)Co2gases: ]

Steel: Composition

Microstructure eld; composition, profile

CO 2 corrosion design Fluid chemistry:

Local/bulk analyses pH, organic acids

Controlling Parameters: Micro-alloying elements

Corrosion inhibition Glycol and methanol

pH-control

Operating condition: Temperature, pressure

Number of phases, water cut (over the life of the field)

r -

Others: Initial production condition

Trend of water cut Carbonate scale Scale inhibitor Other additives

Fig. 3 Parameters affecting CO 2 corrosion design.

20 CO 2 Corrosion Control in Oil and Gas Production--Design Considerations

COMMENTS

Spec i f i c case

PETROLEUM I r I

ENGINEER I

Water analysis IT I Total P or Bubble Point Temperature mole% CO 2 H2S present?

Flow Regime ~ Analysis

PREDICTIVE r-- m MODEL I I , , I I

~ I I .k RATIONALISE I I

I I (vs monitoring I L m "1 and/or inspection ~- --"

I data) I J

+ CORROSION

DAMAGE/RATE

CORROSION ENGINEER

SERVICE CONDITIONS

CONSIDER CHEMISTRY

EFFECT

Positive interaction at all times.

Consider total life of the field.

Check on solution pH. Validate measured pH.

Worst case corrosion rate. Erosion not considered. (Oil/water ratio/flow regime need to be considered, cf. water or oil wetting.)

Check sensitivity to velocity.

Does not predict corrosion rate in presence of H2S.

Determine total accumulative corrosion damage over field life.

Fig. 4 Procedure for predicting C02corrosion damage for a given water composition, CO 2 partial pressure and temperature.

those models which have been fully or partly described in the literature. It is seen that different parameters are used as inputs and it is also seen that some of the key parameters listed in Fig. 3 are not included at all.

Very different results are obtained when the models are run for the same test cases. This is due to the various philosophies used in the development of the models. Some of the models give a worst case corrosion rate based on fully water wetting and little protection from scale and inhibitors. These models have a built-in conservatism and they probably over-predict the corrosion attack significantly for many cases. Other models are partly based on field data and predict generally much

Prediction of the Severity of CO 2 Corrosion

Stratified Annular

Slug

Define risk of water we of pipe wall and criticalareas ~ '

~ _ L 1.

Number of Phases

Bulk flow Local flow conditions conditions

Local flow condition

(at pipewall)

otentia, tacting aqueous p ~

Laboratory testing

i

,.t 1 J Predictive ~__~L rl modelling

r ' - -m I 1 L ~ Field I--J

I monitoring/inspection j L

5 CORROSION DAMAGE/RATE

Bends Welds Damaged Areas

21

Fig. 5 Critical steps in defining CO 2 corrosion damage.

lower corrosion rates. In these models it is assumed that reduced water wetting and/ or formation of protective scale can reduce the corrosion rate from many ram/year to less than 0.1.

The most frequently referenced model has been developed by Shell (de Waard et al.). The first version, based on temperature and Pco2 only, was published in 1975 [2]. The model has since been revised several times. Correction factors for the effect of pH and scale were included in 1991 [32]. To account for the effect of flow a new model was proposed in 1993 where the effect of mass transport and fluid velocity is taken into account [3]. A revised version including steel composition was published in 1995 [33]. This model represents a best fit to a large number of flow loop data generated at IFE [34].

Table 1. An overview of the parameters treated in the various prediction models

Models

Parameters Shell 75 Shell 91 Shell 93 Shell 95 CORMED LIPUCOR SSH KSC fiFE) USL PREDICT

Pco2 O 0 O

Temperature 0 O O

pH O O

Flow rate

Flow regime []

Scale factor []

P tot []

Steel []

Water wetting [] [] [] []

Ca/HCO 3

H2S

HAc

Field data

Ref, 2 32 3 33 3I 35 36 37 38 39

Parameters considered directly

Parameter considered indirectly or not considered highly influential.

Prediction of the Severity of CO 2 Corrosion 23

The CORMED model developed by Elf predicts the probability of corrosion in wells [31]. It is based on a detailed analysis of field experience on CO 2 corrosion mainly from Elf's operations, but also from data supplied or published by others (e.g. Total, Phillips). The model identified the CO 2 partial pressure, in situ pH, Ca2+/ HCO 3- ratio and the amount of free acetic acid as the only influencing factors for downhole corrosion and predicts either a low risk, medium risk or a high risk for tubing perforation within 10 years.

The LIPUCOR corrosion prediction program calculates corrosion rates based on temperature, CO 2 concentration, water chemistry, flow regime, flow velocity, characteristics of the produced fluid, and material composition [35]. The program which is developed by Total is based on both laboratory results and field data. More than 90 case histories have been used in the development.

The SSH model is a worst case based model mainly derived from laboratory data at low temperature and a combination of laboratory and field data at temperatures above 100C [36]. The model has been developed by Hydro, Saga and Statoil in collaboration with IFE.

IFE is developing a new predictive model for CO 2 corrosion based on mechanistic modelling of electrochemical reactions, transport processes and film formation processes. The first part of the model which applies for the case when no surface films are present has been published recently [37].

The USL model predicts corrosion rates, temperatures, flow rates, etc. for gas condensate wells [38]. It is a package of programs developed by University of Southwestern Louisiana.

Predict TM is a software tool developed by CLI international [39]. The basis of the model the de Waard-Milliams relationship for CO 2 corrosion, but other correction factors are used and a so-called 'effective CO 2 partial pressure' calculated from the system pH.

7 CO 2 Corrosion Control

CO 2 corrosion damage and its severity can be mitigated by a number of measures. These primarily fall into two broad categories of (i) modifications to carbon and low alloy steels, to enhance their resistance to corrosion, and (ii) alteration of the environment to render it less corrosive.

7.1. Micro-alloying of Carbon and Low Alloy Steels

Much work has been done to try to improve the corrosion resistance of carbon and low alloy steels with small additions of alloying elements. The corrosion rate is controlled by the transport of the reacting agents through the corrosion product layer and the different alloy additions may affect the protectiveness of the surface film. The microstructure of the steel is also important. It is apparent that the alloying elements and the microstructure do not necessarily have the same effect when the steel is exposed at a low pH, in formation water, in injection water or in inhibited solutions or when different corrosion products accumulate at the steel surface. This may be the reason why there is conflicting information on.this subject in the literature.

Note that the control of corrosion in carbon steel welds was discussed in Section 4.2.

7.1.1. Effect of Chromium

Chromium is the most commonly used alloying element added to steel to improve the corrosion resistance in wet CO 2 environments. Independent work at Sumitomo [40], Kawasaki [41] and IFE [42] shows a beneficial effect of small amounts of chromium in CO 2 saturated water at temperatures below 90C. It is suggested that Cr is enriched in the iron carbonate film and makes it more stable. Alloys with 0.5% Cr seems to be a good choice giving good corrosion properties and hardly any loss of toughness.

At higher temperatures the effect of chromium seems to be more unclear and several authors have reported a reduction in corrosion resistance above 100C for low alloyed chromium steels [5,43,44]. In contrast it has also been reported that the temperature giving a maximum corrosion rate increases with increasing Cr content in the steel [40].

Field experience does indicate an improvement of the corrosion resistance with small amounts of chromium and several companies have recently specified 0.5-1% Cr for their pipelines.

CO 2 Corrosion Control 25

7.1.2. Effect of Carbon

The effect of carbon is linked to the carbide phase, cementite (Fe3C) which forms part of the microstructure of carbon steels. There are two effects of cementite that can be emphasised:

Iron carbide is exposed at the steel surface when the iron is dissolved and it then causes an increase in the corrosion rate. This is explained by a galvanic effect where the cementite acts as a cathode.

The cementite can act as a framework for build-up of a protective corrosion film.

Both these points are connected to the microstructure. The literature is mainly focused on ferrite-pearlite structures and quenched and tempered (QT) steels. A ferrite-pearlite structure can form a continuous grid of cementite after the ferrite phase is removed by corrosion. Under conditions where film formation is impeded (low temperature and low pH) this carbide phase increases the corrosion rate due to a galvanic coupling between the cementite and the ferrite leading to local acidification and further difficulty in establishing protection. Such a grid of carbide could also be a good anchor for a protective iron carbonate film under film forming conditions. A fine ferrite-pearlite structure will improve this tendency. These effects will be stronger at a high carbon content (> 0.15% C).

Quenched and tempered steels contain mainly martensite or bainite where more carbon is in solid solution and the carbide phase does not make a continuous grid as for the ferritic-pearlitic steels. In these steels the galvanic effect will be reduced and the chance of anchoring a protective film less. Most reports on the effect of microstructure maintain that ferrite-pearlite is favourable with respect to film formation [43,45-47] while other workers suggest that QT steels with needle-like carbides can anchor a film better than a ferrite-pearlite steel [44]. This might depend on the very first period of exposure.

Since new pipeline steels have low carbon content (< 0.1% C); the effect of cementite will be of less importance in these types of steels.

7.1.3. Effect of Other Alloying Elements

Nickel is often added to the steels and in welding electrodes for pipeline steels to improve weldability and the toughness of the weld deposit. There has been some disagreement about the effect of small amounts of nickel on CO 2 corrosion [41,42,48]. Most reports indicate a negative effect, but it seems to be slight. Varying effects have also been reported in different sources with small additions of copper [41,44,48].

A positive effect of molybdenum [49], silicon [44,49] and cobalt [39,49] has been reported, but a more systematic study is required to confirm this.

26 CO 2 Corrosion Control in Oil and Gas Production ~Design Considerations

7.2. Effect of Glycol and Methano l

Large quantities of glycol or methanol are often introduced into wet gas-producing systems to prevent and control hydrate formation which can cause plugging problems. Both of these chemicals, if present in sufficient concentrations can inhibit CO 2 corrosion. Of the two, glycol is much more effective and a correction can be made to the predicted corrosion rate to take this into account. Combined with a pH controlling agent, the water/alcohol phase may be rendered less corrosive (Section 7.3).

The glycol additives which are mainly used for hydrate prevention are MEG (mono-ethylene glycol) and DEG (di-ethylene glycol), but TEG (tri-ethylene glycol) can also be used for dehydration. These are effective in reducing the rate of CO 2 corrosion by diluting free water and reducing the corrosivity of the resulting water phase

Methanol, too, can effectively suppress the rate of wet CO 2 corrosion in wet gas transmission systems although it is more difficult to use in the design of corrosion protection of gas pipelines. Operators of wet gas pipelines in the UK Sector of the North Sea have found that with controlled additions of methanol carbon steel corrosion rates can be maintained below I mpy (0.025 mm/y) provided a methanol excess is used. For effective control the concentration of methanol in water at the pipeline reception facilities needs to be kept in excess of 80%.

Although some operators do use glycol as a means of controlling CO 2 corrosion, this is not a recommended practice by others, as corrosion inhibition is preferred and the two effects are not normally considered additive (in some cases less concentrated glycol is used with inhibition). However, it is important to consider the effect that glycol carry-over from drying systems can have in an otherwise 'dry' pipeline. The glycol may absorb any residual water (further lowering the pipeline gas dewpoint) and in doing so create a water-glycol phase which could sustain corrosion, albeit at a low rate.

When evaluating corrosion protection by glycol addition, the actual composition of the condensed glycol/water mixture is of prime importance. Models are used for these predictions, but there are no global models available which can predict all possible situations with respect to carbonate and sulfide films and the corrosion protection levels along wet hydrocarbon pipelines. The commonly used model for design with glycol effects in CO 2 corrosive wet gas pipelines and other systems, is the Shell model [3]. In normal flowing conditions the glycol/water mixture will always be in an equilibrium with the wet gas. Condensation may take place along a pipeline on the relatively colder pipewall in the top section. Nevertheless, the condensing phase will then have the same water content as the stratified glycol, thus reducing its corrosivity.

The pH should be controlled to obtain non-corrosive conditions. In the higher pH ranges above 7-8, the corrosion of carbon steel cannot propagate. Different pH controlling products can be used for this purpose. However, in waters containing calcium or magnesium, there is a risk for scale precipitation at higher pH values and pH control will then be impractical. Similarly, organic acids, e.g. acetic acid etc., can reduce the buffer capacity and hence the pH.

To be cost-effective and environmentally acceptable, it is standard practice to

CO 2 Corrosion Control 27

regenerate (i.e. reboil) the glycol/methanol after use in a system. Over time, the glycol may be partially decomposed and the pH value may decrease. In such a case, pH stabilising to obtain a system pH > 6 is necessary. Possible agents are MDEA or TEA.

A combination of glycol and corrosion inhibitors is sometimes used. As many of the data available on corrosion predictions are laboratory data, a total risk evaluation can result in the need to plan for corrosion inhibitor injection and even implement this from start-up. A question which then arises is how much additional corrosion protection the corrosion inhibitor can give. Laboratory data indicate up to 50% additional corrosion reduction, but this level of corrosion control will be dependent on the actual glycol concentration and type of inhibitor in the system.

The method of using glycol treatments to control CO 2 corrosion in the field should be combined with corrosion monitoring and intelligent pig inspection programme.

7.3. pH Control

7.3.1. The Role of pH

As a dissociation product of the water molecule, H (or its counterpart OH-) is universally involved in the kinetics of aqueous corrosion, and in the equilibria of water chemistry. The pH control or buffering by the natural alkalinity of produced waters (if any) is thus a key issue for the prediction of the CO 2 corrosion rate (both the initial corrosion rate of bare metal, as well as the long term corrosion rate) [50- 52].

7.3.2. Wet Gas Transportation Lines

In long sweet natural gas transmission lines, pH control of hydrate preventors has been implemented successfully [53]. This is a cost effective option to control corrosion, although subject to the absence of Ca 2+ or Mg 2+ ions in the formation water (since they would cause precipitation of scale if pH controllers are added).

7.3.3. Different Chemicals and Their Mechanisms

Various chemicals that have been used in operation to control the pH in natural gas lines are reviewed in this Section. Alkaline additives have changed over the years. Historically, the technique was developed by Elf in Italy (1970s) and Holland (1980s). Further developments have been as follows:

NaMBT (Sodium mercaptobenzothiazole) was used in glyco. However, in the long term it does lead to gunking problems through precipitation of a resin- like compound.

MDEA (methyldiethanolamine) was also used in glycol in the later 1980s. It has a lower freezing point than NaMBT and has no secondary effects.

28 CO 2 Corrosion Control in Oil and Gas Production --Design Considerations

Na2CO3.10H20,(sodium carbonate or 'soda ash'), which may be used either with glycol or methanol, is the proposed new additive as it interacts directly with the CO2/HCO3- equilibrium [50].

All pH controllers remain with the liquid phase during the regeneration of the hydrate preventer by reboiling.

The present understanding of the beneficial effect of pH control is that high pH conditions decrease the solubility limit of siderite (FeCO3), thus favouring the establishment of highly protective corrosion layers. Consequently, the effect of pH is nearly the same for all chemicals (NaMBT, MDEA, NaHCO 3) and all solvents (MeOH, MEG, DEG ..... or fresh water).

The in situ pH should be buffered to about 6.5, whatever the system and temperature being considered. It is worth noting that pH is here an index of the buffering level, which is the same at any temperature. Therefore, pH is measured and reported only at room temperature, whereas corrosion rates, of course, are measured at all the temperatures met along the pipeline.

7.3.4. pH Monitoring

Acetate is not a buffer for carbonic acid [54], and there is a progressive shift of the in situ pH in the presence of free acetic acid, which must be compensated by adding some fresh pH controller. Therefore, there is a need for a periodic monitoring of pH in order to detect and correct any pH shift. This is a simple pH measurement, in a sample where pure CO 2 is bubbled under ambient condition (1 bar) in the presence of the intended chemical. This laboratory measured pH 1 can be used to determine the in situ pH under pressure by:

pH(Pc02 ) = pH 1 - log Pc02 (8)

It is suggested to monitor this on a weekly basis for the first month after start up, and then on a monthly basis.

7.4. Corrosion Inhibit ion

Corrosion inhibitors continue to play a key role in controlling corrosion associated with oil and gas production and transportation. This primarily results from the industry's extensive use of carbon and low alloy steels which, for many applications, are ideal materials of construction, but generally exhibit poor CO 2 corrosion resistance. Clearly economics also has a major part to play in materials selection. As a consequence, there is a strong reliance on inhibitor deployment for achieving cost effective corrosion control, especially treating long flowlines and main oil lines.

7.4.1. Inhibitor Mechanism

Corrosion inhibitors used in hydrocarbon transmission lines are long chain compounds. Generally these are nitrogenous (eg. amines, amides, imides,

CO 2 Corrosion Control 29

imidazolines), but they can also be organophosphates. These compounds are either polar or ionised salts with the charge centred on the nitrogen, oxygen or phosphorus groups and as such they will be surface active. A metal surface in an aqueous environment will have a surface charge and the inhibitor will rapidly be adsorbed onto the metal surface. This process is rapid and reversible (the concentration of adsorbed inhibitor will rapidly decrease if the local environment is depleted). However, once adsorbed in this manner (physisorption) charge transfer between the inhibitor and the metal occurs resulting in a form of chemical bonding which is much more stable m i.e. the inhibitor is chemisorbed. The process of chemisorption leads to the formation of a stable inhibitor film on the surface.

Corrosion is an electrochemical reaction which takes place at various anodic and cathodic sites on a metal surface - - the presence of an inhibitor film of long chain organic compounds depresses both the anodic and cathodic reactions. The mechanisms are not fully clear but as well as providing a physical barrier the inhibitor modifies the surface potential and consequently limits the adsorption-desorption processes and reaction steps that occur in both anodic and cathodic reactions m thus controlling corrosion.

The whole process is critically dependent on both the initial physisorption and subsequent chemisorption processes. These are strongly dependent on the environment (e.g. pH, temperature and liquid shear stresses), the state of the metal surface (e.g. roughness, scales, oxide films, surface damage and carbonate films) and competition from other surface active species (e.g. scale inhibitors and demulsifiers). The last is particularly important in oil and multiphase systems where a wide range of oil-field chemicals may be employed. When selecting inhibitors it is important to carry out full compatibility trials to confirm that the different chemicals in a given package do not detrimentally effect each others performance beyond certain limits. Similarly, in linked systems (e.g. branch lines into a main trunk line) it is recommended that only one inhibitor be used for all of the fluids in the system.

Inhibitor molecules adsorb, however, not only on the bare metal surface but also on the carbonate scale [55]. Thus, the morphology and degree of crystallinity of the scale and, hence, its porosity (homogeneity) will be influenced by adsorbed molecules. The presence of effective inhibitors thus decreases the intrinsic stresses and increases the critical strains for cracking and spalling of the scale [56].

Incorporation of inhibitors in the surface scale and adsorption of inhibitors on it can also lead to drag reducing effects, i.e. to a reduction of wall shear stresses and local flow intensities created at flow imperfections (e.g. pits, grooves, weld beads etc.).

7.4.2. Inhibitor Efficiency and Inhibitor Performance

For an inhibitor to work effectively it must be dispersed to all wetted surfaces and under the system conditions it must be sufficiently effective to provide adequate protection. Calculations of corrosion allowances for given design lives assume effective dispersion and a certain level of success. Areas which cannot be inhibited effectively (e.g. tees) will either have to be clad or allowance made for reduced inhibitor effectiveness.

The inhibitor effectiveness can be defined in two ways, inhibitor efficiency or inhibitor performance.

30 CO 2 Corrosion Control in Oil and Gas Production--Design Considerations

7.4.2.1. Inhibitor Efficiency Inhibitor efficiency is defined from laboratory meas