-
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
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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.
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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.
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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.
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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.
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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,
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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.
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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