Efc 23 co2 corrosion control in oil and gas production maney materials science (1997)

European Federation of Corrosion
Publications
NUMBER 23
A Working Party Report on
CO2 Corrosion Control in Oil
and Gas Production
Design Considerations
Editedby
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
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is responsible for any views expressed
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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.
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Materials in the United Kingdom. These three Secretariats meet at the Board of
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corrosion and certain other journals throughout Europe. More detailed descriptions
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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, CO2,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. CO2is 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 CO2corrosion, 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 CO2corrosion.
This document sets the scene on design considerations specifically related to CO2
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 CO2 corrosion. It also describes means of
corrosion control. It is comprehensive in addressing CO2corrosion 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 CO2
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 CO2 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 RConnell and BPots (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 CO2 Corrosion
Group Workshop
Liane Smith
Chairman of EFC Working Party on
Corrosion in Oil and Gas Production

Contents
Series Introduction ................................................................................................................ vii
Preface ................................................................................................................... ,................ ix
Acknowledgements .................................................................................................................. x
1 Introduction ............................................................................................................... 1
2 Scope ........................................................................................................................... 3
3 The Mechanism of CO2 Corrosion ........................................................................ 4
4 Types of CO2 Corrosion Damage .......................................................................... 6
4.1. Localised Corrosion of Carbon Steel ............................................................... 6
4.2. Localised Corrosion of Carbon Steel Welds ................................................... 7
5 Key Parameters Affecting Corrosion .................................................................... 9
5.1. Water Wetting ..................................................................................................... 9
5.1.1. Water Characteristics ................................................................................ 10
5.1.2. Hydrocarbon Characteristics ................................................................... 10
5.1.3. Top-of-the-Line Wetting ........................................................................... 11
5.2. Partial Pressure and Fugacity 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 Corrosion Prediction Models For Carbon Steel ................................... 19
CO2 Corrosion Control .......................................................................................... 24
7.1. Micro-alloying of Carbon and Low Alloy Steels ......................................... 24
7.1.1. Effect of Chromium ................................................................................... 24
7.1.2. Effect of Carbon ......................................................................................... 25
7.1.3. Effect of Other Alloying Elements .......................................................... 25
7.2. Effect of Glycol and Methanol ........................................................................ 26

vi Contents
7.3. pH Control ......................................................................................................... 27
7.3.1. The Role of pH ........................................................................................... 27
7.3.2. Wet Gas Transportation Lines ................................................................. 27
7.3.3. Different Chemicals and Their Mechanisms ......................................... 27
7.3.4. pH Monitoring ........................................................................................... 28
7.4. Corrosion Inhibition ......................................................................................... 28
7.4.1. Inhibitor Mechanism ................................................................................. 29
7.4.2. Inhibitor Efficiency and Inhibitor Performance .................................... 30
7.4.3. Inhibitor Partitioning and Persistency ................................................... 31
7.4.4. Commercial Inhibitor Packages ............................................................... 34
7.4.5. Inhibitor Compatibility ............................................................................. 34
7.4.6. Inhibitor Deployment ............................................................................... 35
7.4.7. Inhibitor Distribution in Multiphase Pipelines ..................................... 36
7.4.8. Effect of Flow on Inhibition ..................................................................... 36
8 Corrosion Allowance Determination ................................................................. 37
8.1. Design Corrosion Allowance .......................................................................... 38
8.1.1. Design Corrosion Rate .............................................................................. 38
8.1.2. Design Corrosion Allowance Assessment ............................................ 38
9 Design Considerations .......................................................................................... 41
9.1 Well Completions .............................................................................................. 41
9.1.1. Corrosion Design ....................................................................................... 42
9.1.2. Corrosion Monitoring ............................................................................... 43
9.2. Production Facilities ......................................................................................... 44
9.2.1. Corrosion Design ....................................................................................... 44
9.2.2. Multiphase Fluid Behaviour .................................................................... 46
9.2.3. Corrosion Monitoring ............................................................................... 47
9.3 Gas Reinjection ................................................................................................... 49
9.3.1. General Requirements for Gas Reinjection ............................................ 49
9.3.2. Onshore Delivery Lines ............................................................................ 49
9.3.3. Offshore Delivery Lines ............................................................................ 50
9.3.4. Injection Wells And Gas Lift Annuli ...................................................... 50
References ............................................................................................................................ 51

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52 CO2Corrosion Control in Oil and Gas Production ~Design Considerations
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Corrosion "96, Paper 32, NACE, Houston, Tx, 1996.

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.

CO2CorrosionControlin 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 CO2
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 CO2 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 CO2 corrosion damage and the steps necessary to minimise localised
corrosion of carbon steel welds (Section 4).
The key parameters influencing the rate of CO2corrosion 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 ¢=) H2CO3 ~ H ÷ + HCO 3- (2)
The mechanism postulated by de Waard [2-4] is, perhaps, the best known:
H2CO3 + e- --9 H + HCO 3- (3)
2 H --~ H 2 (4)
with the steel reacting:
Fe --9 Fe2+ + 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 CO2Corrosion
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 CO2varies.

4
Types of CO 2 Corrosion Damage
CO 2corrosion 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
CO2 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 CO2partial 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 80-90°C 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 60°C 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.

Typesof CO2CorrosionDamage
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 CO2 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 (70-80°C).

CO2Corrosion 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 CO2corrosion 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 70°C).

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 CO2corrosion to occur there must be water present and it must wet the steel
surface. The severity of CO 2corrosion 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 oil/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:
• Oil/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
• 3rd party entries (mixing effect).

10 CO2Corrosion 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

KeyParametersAffectingCorrosion 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
CO2partial pressures (0-12 bars) and temperatures (20-100°C).
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 Fcondis 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 CO2 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

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
CO2 corrosion results from the reaction of a steel surface with carbonic acid arising
from the solution of CO2 in an aqueous phase m i.e. it is not a direct reaction with
gaseous CO2. The concentration of CO2 in the aqueous phase is directly related to
the partial pressure of CO2in the gas in equilibrium with the aqueous phase. Thus in
CO2corrosion, estimates of corrosion rate are based on the partial pressure of CO2in
the gas phase.
It should be noted that if there is no free gas present then the CO2 content of the
water will be determined by the PCO2of the last gas phase in contact with the fluids
(e.g. the PCO2at the bubble point for well bore fluids; the PCO2in the low pressure
separator gas for fluids in an export pipeline).
Strictly, it is the thermodynamic activity of the CO2in 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 CO2in 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 CO2partial pressure, the CO2fugacity fc02 should
be used with some models:
fco 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 Pco2should 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 1O0 150 200
oC
Total system pressure, bar
Fig. 1 Fugacity coefficient for CO2in methane for gas mixtures with less than 5 mole% CO2[4].
13
However, at higher temperatures (e.g. around 80°C) 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 70-90°C, 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 2corrosion 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 100°C
[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 80-100°C the corrosion rate decreased with increasing temperature.
Conversely, very high corrosion rates have been observed up to 130°C at the top
of some gas wells exascerbated by high rates of water condensation.

14 CO2Corrosion 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 CO2 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 FeCO3supersaturation 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 FeCO3 must not be confused with that of ferrous ions (Fe2+).
(p
LI_
E
C)..
C~.
o~
o~
..O
0
cO
o
oQ)
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].

KeyParametersAffectingCorrosion
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 FeCO3 or Fe304 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 CO2corrosion 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 CO2
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 CO2 gas. As a
result, the contributions of CO2and 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 CO2is still limited. The nature of the interaction of H2S and CO2with carbon

16 CO2CorrosionControlin 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 (FeCO3) will form if CO2is predominant in the gas.
The majority of the open literature does indicate that the CO2 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 CO2corrosion 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 CO2 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 affectingx 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 CO2 saturated water at atmospheric pressure and ambient

KeyParametersAffectingCorrosion 17
temperature. Localised corrosion only took place where there was no wax deposit.
The areas covered with wax were protected from the CO2 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 2corrosion 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 CO2 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 CO2 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 CO2,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 CO2 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 CO2
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 CO2Corrosion 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 CO2
corrosion models and parameters considered in each model. Furthermore, the
parameters which are considered essential in designing for CO2 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 CO2corrosion
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 CO2 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 lineJ
Acid(H2s)Co2gases:]
Steel:
Composition
Microstructure
eld; composition, profile
CO 2 corrosiondesign
Fluidchemistry:
Local/bulk analyses
pH, organicacids
Controlling Parameters:
Micro-alloying elements
Corrosion inhibition
Glycol and methanol
pH-control
Operatingcondition:
Temperature, pressure
Number of phases, water cut
(overthe lifeofthefield)
r-
Others:
Initial production condition
Trend of water cut
Carbonate scale
Scale inhibitor
Other additives
Fig. 3 Parameters affecting CO2corrosiondesign.

COMMENTS
Specific case
PETROLEUM I • r
I
ENGINEER I • •
• Water analysis IT I
• Total P or Bubble Point
• Temperature
• mole% CO2
• 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 Procedurefor predicting C02corrosion damagefor agiven water composition, CO2 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 CO2 Corrosion
Stratified
Annular
Slug
Define risk of water we
of pipe wall and criticalareas ~'
~ _ L
1.
Numberof
Phases
Bulkflow Localflow
conditions conditions
Localflow
condition
(at pipewall)
otentia,
tacting aqueous p ~
Laboratory
testing
i
,.t1 J Predictive
~__~L rl modelling
r'--m I 1
L ~ Field I--J
I monitoring/inspectionj
L
5
CORROSION DAMAGE/RATE
Bends
Welds
Damaged Areas
21
Fig. 5 Critical steps in defining CO2corrosion 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 Pco2only, 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 • • •
Flowrate • • • • • • • •
Flowregime • [] • • • • •
Scale factor • • • [] • • • •
Ptot • • [] • • • • •
Steel • [] • •
Waterwetting [] [] [] [] • • •
Ca/HCO3 • •
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 CO2Corrosion 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 CO2 corrosion
mainly from Elf's operations, but also from data supplied or published by others
(e.g. Total, Phillips). The model identified the CO2partial pressure, in situ pH, Ca2+/
HCO3- 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, CO2 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 100°C [36]. The model has been developed by Hydro, Saga and Statoil in
collaboration with IFE.
IFE is developing a new predictive model for CO2corrosion 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.
PredictTM is a software tool developed by CLI international [39]. The basis of the
model the de Waard-Milliams relationship for CO2 corrosion, but other correction
factors are used and a so-called 'effective CO2 partial pressure' calculated from the
system pH.

7
CO 2 Corrosion Control
CO2 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 CO2 environments. Independent work at Sumitomo
[40], Kawasaki [41] and IFE [42] shows a beneficial effect of small amounts of
chromium in CO2 saturated water at temperatures below 90°C. 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 100°C 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.

CO2 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 CO2corrosion [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 CO2Corrosion Control in Oil and Gas Production~Design Considerations
7.2. Effect of Glycol and Methanol
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
CO2 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 CO2
corrosion by diluting free water and reducing the corrosivity of the resulting water
phase
Methanol, too, can effectively suppress the rate of wet CO2 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 CO2corrosion,
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 CO2 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

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 CO2corrosion 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 Ca2+ or Mg2+ 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.

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 CO2is 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 Inhibition
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 CO2corrosion 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,

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 CO2CorrosionControlin Oil and Gas Production--Design Considerations
7.4.2.1. Inhibitor Efficiency
Inhibitor efficiency is defined from laboratory measurements, as the relative corrosion
rate with and without inhibitor:
CRo-CRinh
Inhibitor efficiency = x 100% (9)
CRo
where GRinh = corrosion rate in the presence of inhibitor and CRo= corrosion rate in
the absence of inhibitor.
The inhibitor efficiency is a function of inhibitor concentration and, is typically
above 90% for successful inhibitors. This figure is often used in the determination of
corrosion severity and the subsequent corrosion allowance. The system inhibitor
efficiency will, of course, be influenced by the dispersion mechanism and, in
particular, how the inhibitor partitions between the different phases present (Section
7.4.3). In this respect, it differs when measured in water alone or water/oil mixtures.
The calculation of corrosion allowances or design lives generally starts by
calculating the expected corrosion rate in the absence of inhibitor m determined by
the prediction models (Section 6.1) and adjusting factors outlined above in Section 6.
The expected corrosion rate is then calculated by multiplying by (1 - f~ 100), where f
is the system inhibitor efficiency; the required corrosion allowance is then the design
life times the inhibited corrosion rate.
Proposed values for the system inhibitor efficiency vary between 80 and 99%. The
corrosion allowance (or design life for a given allowance) is very sensitive to the
value of system inhibitor efficiency chosen; thus an efficiency of 85% will require 3
times the corrosion allowance of an efficiency of 95% and 15 times the corrosion
allowance of an efficiency of 99%; an efficiency of 90% would require an allowance
of 2 and 10 times, respectively.
At 99% the design lives are so large that the effects of temperature and CO2partial
pressure are negligible, i.e. when based on this quality of inhibition.
Until recently, most operators using this approach recommended a figure of 85%
for design purposes. However, in light of past experience and recent advances in
inhibitor performance, design figure have increased to 90%. Tests in the laboratory
have given efficiencies well above 95% and it is felt that, given careful inhibitor selection,
values of 90% can be achieved in the field in straight pipe under typical pipe wall
shear stresses and in the absence of highly energetic flow (e.g. at tees and in slug
flow conditions). This value is more in line with industry practice.
7.4.2.2. Inhibitor Performance
It has been frequently shown that the residual corrosion rate under inhibition does
not display the same sensitivity to operational parameters as the corrosion rate
without inhibitor. It results that the above mentioned approach cannot be but an
approximation, especially if the prediction of CRoitself is questionable. Therefore,
some operators are directly selecting inhibitors according the resulting residual
dissolution rate Cainh. As an example, the choice of chemical and dose rate must
achieve a certain corrosion damage or rate.
In such an approach, the corrosion allowance is chosen first, on a technical and
economical basis. This defines the mandatory inhibitor performance on the basis of

Efc 23 co2 corrosion control in oil and gas production maney materials science (1997)

Efc 23 co2 corrosion control in oil and gas production maney materials science (1997)

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