9.CORROS

CRITICAL REVIEW OF CORROSION SCIENCE AND ENGINEERING

CORROSION—Vol. 59, No. 8 6590010-9312/03/000131/$5.00+$0.50/0

© 2003, NACE International

‡ Corresponding author.* KeyTech Limited, PO Box 275, Camberley, Surrey GU15 2FH,

United Kingdom.** University College London, Torrington Place, United Kingdom.

Carbon Dioxide Corrosion in Oil and GasProduction—A Compendium

M.B. Kermani‡,* and A. Morshed**

ABSTRACT

The present mechanistic understanding and practical impli-cations of carbon dioxide (CO2) corrosion of carbon and low-alloy steels in hydrocarbon production have been reviewed.This is based on the fact that CO2 corrosion is by far themost prevalent form of attack encountered in upstream op-erations. The intent of the review was to provide informationon the mechanisms, highlight key parameters affecting itsoccurrence, and draw attention to areas requiring furtherresearch. The primary focus was placed on two key param-eters affecting CO2 corrosion that had received little system-atic attention, including the morphology, nature, andcharacteristics of the surface film and steel composition,microstructure, and finishing conditions. In addition, the roleof environmental and hydrodynamic variables is briefly pre-sented. The review has highlighted key areas of progressboth mechanistically and industrially and has led to a num-ber of key messages recommending areas for additionalresearch to further the understanding of CO2 corrosionmechanisms to enable improved predictive capabilities forthe effective use and deployment of carbon and low-alloysteels in oil and gas production.

KEY WORDS: acetic acid, carbon steel, carbon dioxide corro-sion, corrosion layer, flow dynamics, iron carbonate, low-alloysteels, metallurgy, mesa attack, oil and gas production

INTRODUCTION

In the search for new sources of oil and gas, opera-tional activities have moved to harsher environmentsin deeper high-pressure/high-temperature wells anddeep water. These have created increased challengesto the economy of project development and subse-quent operations wherein facilities integrity andaccurate prediction of materials performance are be-coming paramount. In addition, the economic movetoward multi-phase transportation through subseacompletions and long infield flowlines has a tendencyfor increased risk of corrosion.

Corrosion, therefore, remains a major opera-tional obstacle to successful hydrocarbon produc-tion, and its optimum control and management isregarded necessary for the cost-effective designof facilities and their safe operations. It has wide-ranging implications on the integrity of many materi-als used in the petroleum industry.

The impact of corrosion on the oil and gas indus-try can be viewed in terms of its effect on capital andoperational expenditures (CAPEX and OPEX) andhealth, safety, and the environment (HSE).1 Corro-sion failures, the majority of which are related tocarbon dioxide (CO2) corrosion,1-5 have been reportedto account for some 25% of all safety incidents,2.8% turnover, 2.2% tangible asset, 8.5% increase oncapital expenditure, 5% of lost/deferred production,and 11.5% increase to the lifting costs.1-3 These areestimated figures and operator dependent, obtained


660 CORROSION—AUGUST 2003

from a number of publications.1-4 The spread ofthese figures are highly dependent on the mannerto which a corrosion control philosophy is plannedand implemented as they vary according to opera-tions and operators. One operator puts the cost ofcorrosion as 30 cents for the production of eachbarrel of oil equivalent (0.3 $/boe) or 1.5% of theturnover.4

The industry continues to lean heavily on theextended use of carbon and low-alloy steels, whichare readily available in the volumes required andare able to meet many of the mechanical, structural,fabrication, and cost requirements. Their technol-ogy is well developed and they represent an economi-cal materials choice for many applications. However,a key issue for their effective use is their poorgeneral and CO2 corrosion performance. Given theconditions associated with oil and gas productionand transportation, corrosion must always be seenas a potential risk. The risk becomes real once anaqueous phase is present and is able to contact thesteel, providing a ready electrolyte for the corrosionreaction to occur.

Oilfield CorrosionOilfield corrosion manifests itself in several

forms, among which CO2 corrosion (sweet corrosion)and hydrogen sulfide (H2S) corrosion (sour corrosion)in the produced fluids and oxygen corrosion in waterinjection systems are by far the most prevalent formsof attack encountered in oil and gas production. H2Scorrosion and materials optimization is covered else-where,3 and corrosion in water injection systems isoutside the present review. The majority of oilfieldfailures result from CO2 corrosion of carbon and low-alloy steels primarily due to inadequate knowledge/predictive capability and the poor resistance of car-bon and low-alloy steels to this type of attack.1-4 Itsunderstanding, prediction, and control are key chal-lenges to sound facilities design, operation, and sub-sequent integrity assurance.

Recent studies clearly have demonstrated that,despite extensive research over the past four de-cades, the mechanistic understanding of CO2 corro-sion remains incomplete. Existing quantitativemodels are unreliable in predicting the actual long-term CO2 corrosion rate of carbon and low-alloysteels, which invariably results in over-specificationof materials and impacts adversely on the cost ofproduction of oil and gas.1-9

The intent of this review article was to capturethe current understanding of CO2 corrosion of carbonand low-alloy steels in hydrocarbon production. Itprovides information on the mechanisms, highlightskey parameters affecting its occurrence, and drawsattention to areas requiring further research. The pri-mary focus was placed on two key parameters affect-ing CO2 corrosion, including the morphology of the

surface film and steel composition. In addition, therole of environmental and physical variables affectingits occurrence is presented. Another key issue is theperformance and characteristics of welds, althoughthis subject was not covered in the present review asit requires detailed and focused attention. The reviewhighlights key areas of progress and draws attentionto the future direction of research and developmentto enable improved and economical design of facili-ties for oil and a gas production.

CO2 CORROSION

CO2 corrosion, or “sweet corrosion,” of carbonand low-alloy steels is not a new problem. It was firstrecorded in the U.S. oil and gas industry in the1940s, followed by several studies since then.6-9 DryCO2 gas by itself is not corrosive at the temperaturesencountered within oil and gas production. It needsto be dissolved in an aqueous phase to promote anelectrochemical reaction between steel and the con-tacting aqueous phase. CO2 is soluble in water andbrines. However, it should be noted that it has asimilar solubility in both the gaseous and liquidhydrocarbon phases. Thus, for a mixed-phasesystem, the presence of hydrocarbon phase mayprovide a ready reservoir of CO2 to partition into theaqueous phase.

CO2 is usually present in produced fluids. Al-though it does not in itself cause the catastrophicfailure mode of cracking associated with H2S,2 itspresence in contact with an aqueous phase neverthe-less can result in very high corrosion rates wherethe mode of attack is often highly localized (mesacorrosion).

CO2 Corrosion MechanismCorrosion of carbon steel in CO2-containing envi-

ronments is a very complex phenomenon and stillrequires further elucidation. Various mechanismshave been proposed for the process. However, theseeither apply to very specific conditions or have notreceived widespread recognition and acceptance.9-19

In general, CO2 dissolves in water to give car-bonic acid (H2CO3), a weak acid compared to mineralacids since it does not fully dissociate:

CO H O CO H O H CO H HCO2 2 2 2 2 3 3+ ⇔ ≅ ⇔ ++– – (1)

As a consequence of the equilibrium described inEquation (1), much debate continues in the literatureas to the rate-determining step (RDS) in the reactionof the dissolved CO2 with a steel surface. Schwenk10

proposed that H2CO3 simply provides a source of H+

ions leading to the normal cathodic hydrogen evolu-tion reaction. de Waard and Milliams11 proposed thatH2CO3 is directly reduced at the steel surface,whereas Ogundele and White12 point to the HCO3

– ion

usuario

Resaltado


CORROSION—Vol. 59, No. 8 661

being reduced directly. The possible RDS in cathodicreactions, therefore, are summarized as follows:

Schwenk

( ): ,– –HCO H e H3 2H H2+ + ⇒ ⇒ (2)

de Waard and Milliams

H CO e H HCO2 3 3+ ⇒ +– – RDS (3)

HCO H H CO3 2 3– + ⇔ ⇒+ and 2H H2 (4)

Ogundele and White

HCO e H CO3 32– – –+ ⇒ + RDS (5)

HCO H e H CO3 2 32– – –+ + ⇒ + (6)

While the Ogundele mechanism only deals with alka-line pH conditions and the Schwenk and deWaardmechanisms are only a possible hypothesis, recentreactions put forward by Crolet, et al.,19 are the mostlikely mechanism encountered. Based on the reactionproposed by Crolet, the anodic dissolution of iron inCO2-containing media is summarized in Table 1 withrespective RDS at different pH conditions.19-20 Thistable goes beyond summarizing the anodic dissolu-tion reactions and includes the respective Tafelslopes derived from each pH condition.

Whichever is strictly mechanistically correct, it isevident that the concentrations of dissolved CO2 spe-cies in solution and the mass transport of dissolvedCO2 to the steel surface have a critical influence onthe reaction and subsequent corrosion rate13 andthat every dissolved species present in the media cancontribute to the cathodic reaction (Ref. 9 and Pots21

and Nesic, et al.22). Hence, there is a clear need to beable to characterize solution chemistry with respectto CO2 dissolution where the resulting acidificationwill depend also on water composition and its buffer-ing capacity.14

Types of CO2 Corrosion DamageCO2 corrosion occurs primarily in the form of

general corrosion and three variants of localizedcorrosion (pitting, mesa attack, and flow-inducedlocalized corrosion).9 In studying CO2 corrosion, aclear distinction should be made between pure CO2

corrosion and a combined interaction of erosion/CO2

corrosion, which may be exacerbated by CO2 corro-sion. The latter characterizes itself in the form ofripple marks, horseshoes, comet tails, and dinosaurfoot prints,8,18 whereas the former is described inthis paper.

Pitting — Pitting occurs at low velocities andaround the dew-point temperatures in gas-producingwells. In the field, only occasional pits have been ob-served, which were either accidental adjacent to non-metallic inclusions or incipient mesa attack.7-8,18 Thepitting susceptibility increases with temperature andCO2 partial pressure. In several related works on pit-ting, Schmitt and coworkers15-17 discussed the effectsof temperature, Cl– concentration, nature of anionsand cations, as well as corrosion inhibitors on the pitinitiation during the first stages of CO2 corrosion ofpure iron and low-alloy steels at 5 bar CO2. They alsoreported that literally all alloys of technical interestmight undergo pitting corrosion in CO2 environmentsat the right conditions. Finally, they showed that Pbadditions inhibited localized corrosion (including pit-ting) through deposition at local anodes. On theother hand, Videm and coworkers23-24 concluded thatthe pitting of carbon steel in CO2-containing environ-ments was almost independent of the chloride con-tent. Therefore, it was different from many othermetal environment combinations. However, the“harmful ion,” if any, responsible for the pitting ofcarbon steels in CO2 solutions was not identified.

The discussion on pitting of carbon steels insweet environments has not reached a convincingconclusion. Various authors attribute the pitting ini-tiation and its propagation to different factors andthere is no generally applicable rule for its prediction.

Mesa-Type Attack — Mesa attack is a type of lo-calized corrosion and occurs in low to medium flow

TABLE 1Mechanisms of the Anodic Dissolution of Iron in CO2-Containing Media19-20

Reaction No. Reaction or Equilibrium pH < 4 4<pH<5 pH> 5

1a HCO3– ⇔ (HCO3

–)ads 1a 1a 1b1b CO2+(OH –)ads ⇔ (HCO3

–)ads

2 (HCO3–)ads ⇒ (HCO3)ads+e – ⇔ ⇔ RDS⇒

3 (HCO3)ads ⇒ (HCO3+)ads+e – ⇔ RDS(A)⇒ ⇒

4 (HCO3+)ads+OH – ⇒ (CO3)ads +H 2O RDS⇒ ⇒ ⇒

5 Fe – (CO3)ads + H2O ⇒ Fe+++HCO 3–+OH – ⇒ ⇒ ⇒

1 → 5 Tafel slope (mV/log) 60/2 = 30 60/1.5=40 60/0.5= 1201 → 5 H+ reaction order –2 –1 01 → 5 CO2 reaction order 1 1 1

(A) RDS = rate-determining step.



conditions where the protective iron carbonate filmforms but it is unstable to withstand the operatingregime. It manifests itself in large flat-bottom stepswith sharp edges. Corrosion damage in these loca-tions is well in excess of the surrounding areas.9

Figure 1 is an example of mesa attack experiencedon an internal surface of pipelines exposed to CO2-containing environments.

Crolet, et al.,25 proposed that the microstruc-turally formed galvanic coupling between steel (itsferrite phase) and the cementite (Fe3C) layer was onepossible cause to promote mesa attack in sweet envi-ronments. According to the same author,18 mesa at-tack was observed in mature oil wells or, conversely,in young gas wells under high pressure of acid gases.Even in the presence of high fluid flow rates, itscharacteristics were totally different from the typicalfeatures of erosion corrosion. Mesa attack appearedto be a little sensitive to the velocity of water in thepipe, but extremely dependent on fluid composition.18

Ikeda, et al.,26 attributed the initiation of mesaattack to the competitive film formation reactionsbetween ferrous carbonate (FeCO3) and magnetite(Fe3O4). Although, in actual field conditions, Fe3O4

has not been detected.18,27 The codeposition of bothcompounds could initiate the mesa corrosion by dis-turbing the protective film formation. They concludedthat the initiation mechanism of mesa corrosion wasclosely related with the formation of a poorly protec-tive FeCO3 film or the localized destruction of aprotective film.

Videm and coworkers28-30 showed that flow-induced mesa attack could occur in water saturatedwith FeCO3 under turbulent flow conditions wherefilm formation is prevented locally. In similar work,Dugstad and coworkers30-31 demonstrated that the

initiation of mesa attack was a result of the marginalfilm stability of FeCO3. However, as indicated earlier,chemical instability of the film has a more pro-nounced influence on the formation of mesa attackthan any mechanically driven effect by fluid dynam-ics.27 Dugstad then discussed the relation betweenFe2+ content of the environment and the initiation ofmesa attack for sweet environments.31 According tohim, when mesa attack has initiated, a galvanic cellwould probably establish where the film-covered sur-face was cathodic and the mesa-attacked areas wereanodic.31 As described later, trace concentrations ofCr alloying element when added to carbon steel re-duced mesa attack to a great extent.32-33

Again, the exact conditions under which mesaattack forms are poorly understood and further sys-tematic studies are necessary to prevent its occur-rence in the field.

Flow-Induced Localized Corrosion — This form ofcorrosion starts from pits and/or sites of mesa attackabove critical flow intensities. It then propagates bylocal turbulence created by the pits or steps at themesa attack or by protruding geometry. The localturbulence combined with the stresses producedduring scale growth may destroy existing scales.15-17

Once the scale is damaged or destroyed, the flowconditions then may prevent reformation of protec-tive scale on the exposed metal.9,16-17 Flow-inducedlocalized corrosion attack is principally observed inlaboratory experiments in the absence of completecontrol of fluid chemistry.

KEY FACTORSINFLUENCING CO2 CORROSION

CO2 corrosion is influenced by a number of pa-rameters, including environmental, physical, andmetallurgical variables as illustrated in Figure 2.The majority of these have been covered extensivelyby a number of authors and captured elsewhere.6,8-9

Notable parameters affecting CO2 corrosion include:—fluid makeup as affected by water chemistry,

pH, water wetting, hydrocarbon characteris-tics, and phase ratios9,34-36

—CO2 and H2S content9,37-40

—temperature9,34-35,41

—steel surface, including corrosion film mor-phology, presence of wax, and ashphaltene9

—fluid dynamics9,29,39-41

—steel chemistry32-33,38,42-45

All parameters are interdependent and can inter-act in many ways to influence CO2 corrosion. In thepresent article, emphasis has been placed on two keyissues relating to metallurgical variables and surfacefilm as key parameters not covered systematicallyelsewhere. Other influential parameters are coveredextensively by others8-9,34 and have been given only abrief mention here.

FIGURE 1. A typical example of severe mesa attack experienced oninternal surfaces of pipelines transporting CO2-containinghydrocarbon fluids (courtesy of Institute for Energy Technology, IFE).



Environmental ParametersEnvironmental factors that affect the inherent

corrosivity of the aqueous phase therefore will affectCO2 corrosion. These include solution chemistry,CO2 partial pressure, temperature, the in-situ pH,H2S, and the effect of organic acids.

Solution Chemistry and Supersaturation — Whilethere are still limited debates about the mechanismof CO2 corrosion in terms of which dissolved speciesare involved in the corrosion reaction, it is evidentthat the resulting cathodic corrosion rate is depen-dent on the partial pressure of CO2 gas and tempera-ture. Partial pressure of CO2 gas thus will determinesolution pH and the concentration of dissolved spe-cies for a given temperature.

Supersaturation plays a vital role in the forma-tion and stability of a protective corrosion layer.Supersaturation is defined as “log [A+][B–]/Ksp” for aninsoluble salt (AB) having an equilibrium reaction ofAB = A+ + B–, where A+ and B– are ionic species andKsp is the solubility product. In any sweet environ-ment, a particularly insoluble salt can play an impor-tant role in reducing the corrosion rate. Highsupersaturation of A+ and B– leads to precipitation ofa corrosion layer/film that therefore would reducethe corrosion rate through several kinds of effects,including:18

—provision of a “diffusion barrier” (extended dif-fusion length between the metal substrate andthe corrosive medium);

—formation of a low-porosity protective layer(lowering the exposed surfaces compared withthe steel surface and hence less areas to becorroded);

—creation of concentration gradients of the prin-cipal chemical species (Fe++ and HCO3

–). This ispotentially the most influential and particu-larly difficult to model. Ingress of solution tosoak the porosity leads to steep concentrationgradients, which may induce a significant shiftof the local pH and water chemistry from thebulk conditions, and therefore, a genuine ef-fect of “liquid surface state.”

Altogether, the precipitation rate and protectivecharacteristics of any scale depend heavily on thesupersaturation of the bulk solution. Hence, anyvariations in this level of supersaturation could affectthe severity of the corrosion. For iron carbonate sys-tems, this can be portrayed as a reaction similar to“Fe(HCO3)2 ⇔ FeCO3 + H2CO3.”

46 The interdependencyof supersaturation with the respective rates of irondissolution and reprecipitation is shown in Figure 3as a function of temperature. Figure 3 illustrates thatwhile iron carbonate solubility to achieve saturationremains a little dependent on temperature, the limitof supersaturation is achieved at lower Fe2+ concen-trations with increasing temperature and hencefacilitates the formation of FeCO3.

31

CO2 Partial Pressure — CO2 partial pressure hasbeen used in pH calculations and corrosion rate

FIGURE 2. CO2 corrosion, the influential parameters.

usuario

Resaltado

usuario

Resaltado

usuario

Resaltado



measurements by many authors.6,9,11,36,37,47-49 In mostcases, a relationship has been developed between theCO2 partial pressure and corrosion rate. However,with some exception,36,48 the majority of pH calcula-tions in these relationships do not take on boardthat produced water cannot stay supersaturated inCaCO3. It also should be noted that for gas wellswith increasing pressure, the non-ideality of thenatural gas will play an increasing role. Instead ofthe CO2 partial pressure, the CO2 fugacity (fco2)should be used.50 The difficulty is that for the pur-pose of homogeneity between nonideal phases, whenfugacity is used for the gas phase, an activity coeffi-cient (γco2) should also be introduced for the waterphase. Unfortunately, fco2 is often available from“PVT” data, but rarely γco2,

36,48 and this may be thereason for the simplistic use of fco2 in the predictionof corrosion rates.

Operating Temperature — The operating tempera-ture strongly affects the nature, characteristics, andmorphology of surface film, which, in turn, influ-ences the CO2 corrosion process. At temperaturesin excess of ca. 80°C, the solubility of FeCO3 in thesolution is decreased and high supersaturation leadsto FeCO3 precipitation.41 At low temperature ranges(< ca. 70°C), corrosion rate progressively increaseswith temperatures up to an intermediate tempera-ture range (between 70°C to 90°C), after which thecorrosion rate then diminishes. However, at siteswhere breakdown in the formation of FeCO3 occurs,

corrosion process proceeds unhindered, which maylead to severe localized attack. This is an importantdesign consideration.9 It is thought that the increaseof corrosion rate in the low-temperature range is dueto an increase of mass-transfer rate as a result offlow effect and slow FeCO3 formation rate.27 Conse-quently, after the formation of the protective scale, adiffusion process may become the RDS in the corro-sion process.19 However, as described in the SolutionChemistry and Supersaturation Section, this doesnot rule out the potential for the occurrence of local-ized corrosion or the formation of nonprotective cor-rosion scales (i.e., when the aspects of solid surfacestates [diffusion barrier and porous layers] are su-perseded by those of liquid surface states [membraneeffect and local water chemistry]27), as described inthe section on surface film.

In Situ pH — Solution pH plays an important rolein the corrosion of carbon steels by influencing boththe electrochemical reactions that lead to iron disso-lution and the precipitation of protective scales thatgoverns the various transport phenomena associatedwith the former. Under certain conditions, solutionconstituents of the aqueous phase will buffer the pH,which can lead to precipitation of a corrosion scaleand the possible lowering of corrosion rates. Itshould be noted that, as described in the section onfilm formation, in certain circumstances the corro-sion layer can even be corrosive and increase theseverity of attack.8-9,19,27

As an example, by increasing pH from 4 to 5, thesolubility of Fe++ is reduced five times; for an increasefrom pH 5 to 6, this reduction is around 100 times.8

A low solubility can correspond to higher supersatu-ration, which therefore accelerates the precipitationprocess of FeCO3 film. For pH values >5, the prob-ability of film formation is thus increased and thatcan contribute to the lower corrosion rates observed.It must be noted that the solubility of the FeCO3

should not be confused with that of the iron ion.8-9,18

Effect of H2S — Ignoring the cracking aspects ofcorrosion problems associated with sour service, lowlevels of H2S can affect CO2 corrosion in differentways. H2S can either increase CO2 corrosion byacting as a promoter of anodic dissolution throughsulfide adsorption and affecting the pH or it can de-crease sweet corrosion by forming a protective sulfidescale. The exact interaction of H2S on the anodic dis-solution reactions (Table 1) is not clear.

For similar conditions, oil and gas installationscould experience lower corrosion rates in sour condi-tions compared to completely sweet systems. This isattributable to the fact that the acid created by thedissolution of H2S is about three times weaker thanthat of carbonic acids, but H2S gas is about threetimes more soluble than CO2 gas. As a result, theeffect of both CO2 and H2S gases on lowering thesolution pH and potentially increasing corrosion rate

FIGURE 3. Fe++ solubility in pure water as a function of temperatureat 0.1 MPa CO2 partial pressure. Open squares represent resultsobtained with corroding steel present, where the water volume tosteel surface area ratio is 4 cm3/cm2. Filled triangles are Fe++

concentrations calculated from pH. Filled squares are resultsobtained with solid iron carbonate. The dashed line is iron carbonatesolubility calculated from IUPAC data.31

usuario

Resaltado

usuario

Resaltado

usuario

Resaltado



are fundamentally the same. In addition, H2S mightplay a significant role on the type and propertiesof the corrosion films, improving or underminingthem.8-9

Videm, et al.,38 and Mishra, et al.,37 have re-ported two opposing results concerning H2S. Whilethe former has reported that very small amounts ofH2S in CO2-containing water augmented the corro-sion rate, the latter has argued that small amountsof H2S had some inhibitive effect on CO2 corrosion ofsteels. They attributed this to the formation of aniron sulfide film that apparently was more protectivethan FeCO3.

Many papers have been published on the inter-action of H2S with low-carbon steels.6,8-9,39-40,51-52 How-ever, literature data on the interaction of H2S andCO2 is still limited since the nature of the interactionwith carbon steel is complex. The majority of openliterature does indicate that CO2 corrosion rate is re-duced in the presence of H2S at ambient tempera-tures. Nevertheless, it must be emphasized that H2Salso might form a nonprotective layer and that itmight catalyze the anodic dissolution of bare steel.Steels may experience some form of localized corro-sion in the presence of H2S, although very little infor-mation is available. Published laboratory work hasnot been conclusive, indicating that there is a needto carry out further studies to clarify the mechanism.A recent failure showed how the corrosion rate in thepresence of a high concentration of H2S might behigher than predicted using CO2 corrosion predictionmodels. However, in spite of the work on H2S corro-sion of steels, no equations or models are availableto predict corrosion, as is the case for CO2 corrosionof steels.9

Effect of Acetic Acid — Organic acids present inproduction fluids has long been considered to signifi-cantly influence and complement CO2 corrosion. Theinfluence has been shown to occur systematically inall field conditions where CO2 corrosion was ob-served.18,27,53 Addition of acetic acid (HAc) to the testenvironment reduces the protectiveness of the filmsand increases the sensitivity to mesa attack. Thisattributes to a lower Fe2+ supersaturation in thecorrosion film and at the steel surface. Significantreduction in film stability was observed when theconcentration of undissociated HAc in the solutionwas increased from 0.05 mmol to 0.2 mmol, but theresults are too few to give more accurate thresholdvalues.19,53-56

Crolet and Bonis14,55 make the point that CO2-induced acidification also can cause partial re-asso-ciation of anions, such as acetates and propionates,to form organic acids. Such weak acids then will in-crease the oxidizing power of H+ by raising the limit-ing diffusion current for cathodic reduction (cf.Reaction [2]). The presence of such acids also willtend to solubilize the dissolving iron ions and sup-

press FeCO3, or oxide film formation, which canotherwise passivate the steel surface.25,35,55

It is also often observed, at least in laboratorytests, that water or brine acidified with CO2 to a givenpH produces a more corrosive solution than acidify-ing to the same pH with mineral acid. This is gener-ally attributed to the fact that because carbonic acid(H2CO3) is not fully dissociated in solution, it pro-vides a reservoir of H+ ions over and above that deter-mined by the solution pH (–log[H+]). In essence, thisis the same effect as that once cited by Crolet andBonis14 in the presence of organic acids (weak acids)(i.e., increasing the oxidizing power of H+). For lowconcentrations of HAc (very few mM), however, theeffect cannot but remain negligible with respect tothe tens or hundreds of mM of dissolved CO2.

19 Inaddition, the presence of HAc may change themechanism of the anodic dissolution of iron throughcompetitive adsorption of acetate ions, CH3COO–

(or Ac–) and HCO3–, although this was shown to have

only a slight inhibiting effect.19,55

Generally, the presence of HAc caused a signifi-cant increase in the corrosion rates in CO2 environ-ments.53,56 HAc (along with other organic acids) couldjeopardize the protective corrosion product scalesformed in top-of-the-line corrosion.57

At low CO2 partial pressure, CO2 corrosion disap-pears, but in certain fields, it can be replaced by agenuine “HAc corrosion.” It has been shown that thiswas not caused by any influence of the HAc, eitheron the cathodic reaction of H+ or on the anodic disso-lution of iron, but rather by its effect on the protec-tiveness of the corrosion layer. In the presence oftraces of free HAc, the majority of corrosion layers onbare metal was no longer FeCO3, but iron acetate,which had a much greater solubility.19

In a similar work,25 it has been reported thatat a given pH, any replacement of a concentrationor a flux of bicarbonate by an equivalent quantityof acetate would considerably increase the localsolubility of iron. This decreases the protectivenessof the corrosion layer in proportion, by increasingiron concentration gradients, and therefore allowingand subsequently raising the fluxes of corrosionproducts, which potentially can be removed throughthe layer. An overview of the concentration gradientof acetate ions close to the metal surface is shownin Figure 4.23

The presence of HAc is a key issue in CO2 corro-sion, which requires further extensive studies.

Physical ParametersAlong with environmental and metallurgical pa-

rameters, physical parameters play an important rolein CO2 corrosion of carbon and low-alloy steels byinfluencing hydrodynamics of the system and the in-terface between the environment and the steel sub-strate. These include water wetting, wax effect,

usuario

Resaltado

usuario

Resaltado



surface films, crude oil, and fluid dynamics and aremostly covered by others.8-9 Their interactive andcomplementary influences affect the onset of film for-mation and removal. These effects have been high-lighted briefly here.

Water Wetting — CO2 corrosion occurs whenwater is present in the system and it wets the steelsurface. The intensity of CO2 corrosion attack in-creases with the time during which the water phaseis in contact with the steel surface. Therefore, thewater content (water cut) and the notion of waterwetting are important variables. There are at leastthree different notions of water wetting as follows:58

—Hydrodynamic concept focuses on modeling acontinuous water phase at the fluid/wall in-terface, which is primarily over the corrosionlayer. However, it is evident that corrosiondoes not occur over the corrosion layer, butbeneath it. This concept therefore cannot bedirectly relevant to corrosion modeling asinfluenced by water wetting.

—Electrochemistry and surface physics conceptrelates to liquid in direct contact with themetallic phase. This can be, in part, highly in-fluential in the modeling of water wetting.

—CO2 corrosion-related concept in which liquid-soaked porous film continues to hold water,even if the bulk phase in contact with the wallis temporarily either pure oil (in oil lines) orjust a thin, wet film (in a pure gas line withoutany ongoing water condensation). This pro-vides a favorable boosting for the sealing ofcementite or hydrated mill scales during thecorrosion process and, as a consequence,facilitates the onset of protectiveness in anoriginally nonprotective film.27 Such circum-stances can occur during shutdown periodsor in slug flow conditions.

Therefore, the influence of water cut on corro-sion rate should be considered in association withthe flow velocity and the flow regime effects in thecontext of the above notions of water wetting, par-ticularly using a combination of the second andthird notions.27

It is known that emulsions can form in oil/watersystems. If a water-in-oil emulsion is formed and thewater is held in the emulsion, then the water wettingof steel is prevented or greatly reduced, causing thecorrosion rate to decrease. If, on the contrary, anoil-in-water emulsion is formed, then water wettingof steel will happen. The transition from a water-in-oil emulsion to oil-in-water occurs at around 30% to40% water in many oil lines and, in a straight pipewith emulsified liquids, an obvious increase in thecorrosion rate can be observed.59 So, as a rule ofthumb, for water cuts <30 wt%, the corrosion rate isoften significantly reduced,9,59 although there aremany exceptions to this.60 The water cut thresholddepends primarily on the maturity of hydrocarbon(immature oils still contain natural surfactants) andthe nature of its kerogen (I, II, III)27 as explained in alater section.

Corrosion Film Characteristics — Characteristicsof corrosion product significantly affect the CO2 cor-rosion process. Formation of surface film can providesubsequent protection, enhanced corrosion, or un-controlled reaction, all subject to the nature, mor-phology, and growth habit of the corrosion product.Due to the importance of this subject, it is describedin a separate section on film formation.

Effect of Wax — The presence of wax in oil pipe-lines can influence CO2 corrosion damage in twoways, either exacerbating the damage or retardingthe process. These are dependent on the nature ofwax layer and subject to flow dynamics, temperature,and other physical parameters. Based on data gath-ered in sweet oil lines in the U.S., a layer of wax (par-affin) deposited on a carbon steel substrate causedheavy pitting in anaerobic sweet environments. Theproposed corrosion mechanism is the diffusion ofCO2 through the wax layer, which can provide a largecathodic area that promotes anodic dissolution ofsteel at discontinuities of the wax layer.9 However,generally, wax can provide a degree of protection,albeit its protection is not reliable.

Effect of Crude Oil — Corrosion tests conductedon steel in brine environments in the absence ofcrude oil do not give an accurate representation ofthe behavior of the steel corrosion in a crude oil/brine production environment. This can lead to grosserrors when using the test results to estimate poten-tial corrosion problems.61-63

Although there has not been any specific investi-gation on the effect of crude oil type on protective-ness of FeCO3 scale, it has been determined thatcrude oils modify the morphology, composition, and

FIGURE 4. Illustration of possible HAc enrichment in a corrosionlayer as a result of internal acidification and galvanic couplingbetween steel and cementite.25

usuario

Resaltado

usuario

Resaltado

usuario

Resaltado

usuario

Resaltado



compaction of corrosion products for the differentoil/water ratios evaluated.64 Hydrocarbon appears todestabilize the formation of a passive FeCO3 film, ac-celerating the “localized” corrosion.27,61-62 Competitivewetting of steel surfaces by water and then by oil hasbeen reported to play an important role.65-66

A combination of water cut and hydrocarbontype play a key role in affecting CO2 corrosion. Inthis, the maturity of hydrocarbon (immature oils stillcontain natural surfactants) and the nature of itskerogen (I, II, III)27 are main issues. While this infor-mation is extremely important, it is rarely recordedor reported. It should be noted that some crude oilsalso release natural corrosion inhibitors, which aid inlowering the corrosion rate.27

Crude oil plays an important and differing roleon CO2 corrosion and has not received due attention.

Flow and Erosion — The effect of flow on CO2

corrosion still remains a contentious area in the pre-dictive processes. This effect should be discarded inpredictive modeling unless it is fully defined and con-trolled by the production process throughout theproduction life. However, it is not only fluid contentthat needs to be determined—the flow regime is ofequal importance, which, for multi- or mixed phasefluids, will determine whether water wetting of thesteel surface will occur. Clearly, if continuous hydro-carbon wetting occurs, then the corrosion risk willbe extremely low.59 Key factors here are oil/waterratio and emulsion tendency/stability. For manycrude oils, the presence of a water cut > ≈30% willlead to water becoming the continuous phase for afully mixed oil/water system, such that corrosionthen becomes a continuous potential risk.59,62 Simi-larly, if the gas/oil ratio (GOR) is >5,000, then con-tinuous water wetting by the condensed water canbe expected.8-9

The flow parameter currently favored for deter-mining the effect of velocity on corrosion rate andscale and inhibitor film formation/stability is liquidshear stress at the pipe wall. Although there is lim-ited reported data on upper limits regarding shearstress, a figure of 100 Pa for C-steel above which dis-ruption to surface films becomes a concern is consid-ered by some as appropriate.67 However, it must berecognized that for specific situations it may be nec-essary to conduct laboratory tests under simulatedflow conditions.

Laboratory testing becomes particularly criticalwhere erosion, as a result of the presence of particu-lates, is a concern. There are no industry guidelinesthat adequately cover this situation. The commonlycited API RP-14E68 recommended practice strictlyrefers to pure gas-in-liquid-induced erosion (i.e., noparticulates present) and applies the basic formula:

V Ce m= ( )/ ρ (7)

where Ve, mixed velocity (ft/s or m/s), ρm, mixed fluiddensity (lb/ft3 or kg/m3), and C are constants.

The relationship is essentially empirical as is thevalue of the constant (C) used for a given material.This is more often than not based on the individualoperator experience.

Metallurgical ParametersChemical composition, heat treatment, and

microstructural features play important roles oncorrosion of carbon steels in CO2 environments.

While most authors have reported the beneficialeffects of chromium additions,26,29,42-45,68-79 there is notyet a consensus on the optimum amount of Cr in thesteel structure. Apart from Cr, molybdenum has beenfound to improve the corrosion resistance of carbonsteels.42 In a related work, Videm and Dugstad23

showed that small amounts of Cu, Ni, Cr (and possi-bly Mo) increases the corrosion potential of carbonsteels, making it more noble. However, Cu additionsmay have a side effect on inhibitor efficiency as re-ported by Gulbrandsen and Nyborg.43

A laboratory study has shown that the sulfurcontent of carbon steels appears to influence the CO2

corrosion rate as well. Certain high-S carbon steelswere more corrosion resistant than low-S carbonsteels in low-shear-stirred CO2 corrosion tests,74

although the steel samples used in this work werenot representatives of oil industry grades and thepractical implication of the work is uncertain.

Work by Kermani and coworkers44,80 has pavedthe way to developing an optimum metallurgy ofcarbon and low-alloy steels for both downhole andtransportation facilities through addition of microal-loying elements like V, Ti, Mo, Cu, and Cr.

ALLOYING ELEMENTS

It is now well established that small quantities ofchromium (0.5 wt% to 3 wt%) can offer improved cor-rosion resistance of low-alloy steels in CO2-contain-ing media by promoting the formation of a stable,protective chromium oxide film.8-9,33,72,77 It also hasbeen appreciated recently that for carbon and low-alloy steels, there may be a correlation between pro-tectiveness of the corrosion layer in the active stateand a possible “passivation” by a “super protective”layer.8,72 The development of novel carbon and low-alloy steels with superior resistance to CO2 corrosionusing metallurgical conditioning recently has beenmade in the laboratory and subsequently by indus-trial casts covering a wide range of parameters in-cluding microalloying constituents, heat treatmentprocessing, and steel production scenarios. Corro-sion performance and properties of optimum steelsdeveloped in this project have been verified throughevaluation of the industrial casts,80 offering superiorCO2 corrosion while tolerating H2S corrosion for ap-

usuario

Resaltado

usuario

Resaltado



plication in Region 2 of ISO-15156.81 The philosophyunderlying the work of Kermani and coworkers44,80

was based on a combination of two principles:—lowering C and adding carbide-forming alloy-

ing elements to maximize the effect of a givenaddition of chromium and molybdenum, byensuring that they remain in solid solution;

—achieving the desired properties bymicroalloying additions and mechanical andheat treatments.

Steel compositions were designed with low-carbon contents and contain microalloying additionsof stronger carbide-forming elements (V, Ti, and Nb).The intention was that these microalloying elementsshould preferentially combine with the carbon in agiven steel, leaving Cr and Mo uncombined in theferrite to provide enhanced corrosion resistance. Inaddition, the presence of Si can lead to bainite for-mation under normalized conditions. Thus, this ele-ment, together with Ni, was used to bring back thestrength caused by the loss of carbon. The transfor-

mation characteristics of the steel and the heat treat-ment following initial cooling was studied to allowmeasures to prevent heat-affected zone (HAZ) crack-ing during welding. The strength and toughness re-quirements were met through grain size refinement,the promotion of bainitic microstructure, and theprecipitation strengthening effect of the alloy carbides.

Extensive metallurgical and corrosion character-ization of laboratory heats44 and industrial casts,80

produced with new but economically realistic rangesof alloy contents, has led to the development of novelcategories of low C, Cr-containing steels with supe-rior resistance to CO2 corrosion. The work utilizedthe existing metallurgical knowledge of modern steelproperties and extensive knowledge of steel corrosionbehavior to identify the role of alloying elements todefine optimum steel compositions likely to meet thestrength, properties, weldability, and corrosion resis-tance targets required by the oil industry.

Based on the outcome of this extensive study,certain compositional trends were confirmed. The re-sults are summarized in terms of individual alloyingelements in Figure 5, as follows:

Cr — An optimum Cr content had a significantbeneficial role on the CO2 corrosion performanceof the steels. They categorized the effect of Cr asfollows:

—5% Cr category: the lowest corrosion rate—3% Cr category—1.5% Cr category—1% Cr category—0.02% Cr category: the highest corrosion rateAn overview of these categories are presented

schematically in Figure 6, illustrating a progressivereduction in corrosion rate with increasing Cr con-tent, the extent of which is subject to other alloyingconstituents and heat treatment.

While 3% Cr proved to offer a 10-times reductionin corrosion rate, 1.5% Cr was not sufficient to en-sure this level of resistance. The optimum level of Craddition was not determined, albeit a level between2% to 3% Cr was considered essential to achieve theexpected improvement in corrosion performance sub-ject to additional microalloying constituents.

V — V had a major beneficial effect on reducingcorrosion rate.45,80

Ti — Ti had some beneficial effects on the corro-sion rate, although inconsistent, and some unsatis-factory effects on mechanical properties. Control ofproperties in the Ti steels proved difficult, althoughTi additions could help to reduce HAZ hardness.

Mo — Mo had no effect on the corrosion rate inthe active state at low pH, but helped to get a genu-ine passivation in case of upward pH shifts beneathan already protective corrosion scale.

Si and Cu — These microalloying elementsshowed beneficial effects on CO2 corrosion comple-mentary to the effect of Cr, albeit subject to the

FIGURE 5. Schematic presentation of relative effect of additionalmicroalloying elements on corrosion rate.44,80

FIGURE 6. Schematic overview illustration of different categories ofsteel ranked according to their Cr level.44,80



microstructure, heat treatment, their interaction,and corrosion conditions.

It is concluded that V-microalloyed steel contain-ing Cr, Si, Mo, V, and Cu is the most promising com-position in terms of corrosion resistance andmechanical properties.44-45,80 This steel offered goodlevels of strength and toughness and good hot ductil-ity, making it suitable for continuous casting.Weldability is an issue for this composition, makingit only readily suitable at this time for downhole ap-plications (e.g., threaded connections).80 Furtherstudies are underway to improve the weldability byreducing C, V, and Mo contents, without compromis-ing corrosion resistance. A very small addition of Ti(below stoichiometry with nitrogen) could be used toreduce HAZ hardness.78

While corrosion rates of reference steels (X70,X65, or L80) increased with time, the new composi-tion steels exhibited progressively reduced corrosionrates with time, stabilizing after the initial expo-sure—a clear indication of the progressively protec-tive nature of the corrosion film that formed on theexperimental steels and the necessity to carry outlong-term corrosion experiments (in excess of 7 days)to allow steady-state conditions. The conclusiondrawn is that, as expected, Cr is effective above acertain level, below which it is detrimental to the an-odic reaction on bare steel. Inconsistency in the cor-rosion performance of low-Cr-containing steels hasbeen experienced by a number of operators.8-9,73,76

The data demonstrated that the calculated valueof “free Cr and V,” generally, proved to be good indi-cators of CO2 corrosion performance—nevertheless,microalloying constituents and resultant microstruc-ture have influential and complementary roles.44,80

SURFACE FILMS; CORROSION LAYERS

CO2 corrosion of carbon and low-alloy steels isstrongly dependent on the surface films formed dur-ing the corrosion processes. The protectiveness, rateof formation/precipitation, and the stability of thefilm control the corrosion rate and its nature (generalcorrosion or localized corrosion, especially mesa at-tack). Precipitation kinetics of FeCO3 film is affectedby the iron and carbonate concentrations, and itssubsequent formation and growth are extremely tem-perature sensitive.46 It is not the thickness of the filmbut the structure and its morphology that leads tolow corrosion and protectiveness.9,19 It is interestingto note that a corrosion layer containing the samesolid components can be either extremely protective82

or not very protective, or can even be corrosive.19,25 Ithas not been very clear why under some conditionsthese scales form and mitigate further corrosion andsometimes, in spite of favorable thermodynamic con-ditions for their formation, they do not precipitate atall and the corrosion continues unhindered.

In general, the protective characteristics of a cor-rosion film/layer depend on both the carbon steelcharacteristics (microstructure, heat treatment his-tory, alloying elements) and environmental variables(solution pH, temperature, solution composition, flowrate, etc.). The former has been covered earlierthrough influencing and modification of steel chemis-try and treatment processes.8-9,41-44,47,70-79 This sectionfocuses on the latter and discusses how film/scaleproperties are influenced by the environmental fac-tors, bearing in mind:

—their properties and effects on corrosion rate—effects of various variables on the properties of

the film/layer—modification of the surface films and its growth

habitsFurther studies that are necessary for the im-

provement of the corrosion of carbon and low-alloysteels in CO2-containing environments throughenhancing the properties of the surface film areproposed.

Film FormationBased on extensive observations made by many

workers, corrosion films in the 5°C to 150°C tem-perature range in water containing CO2 can generallybe divided into four main classes:

—transparent films—iron carbide (Fe3C) films—iron carbonate (FeCO3) films—iron carbonate plus iron carbide (Fe3C +

FeCO3) filmsThese are reviewed in this section and their over-

all characteristics are summarized in Table 2.Transparent Films — Transparent films are

rarely cited in the literature. They are <1 µm thickand only observed at around room temperature. Thefilm appears to form faster by reducing the tempera-ture below ambient. This class of film is not thermo-dynamically the most stable solid corrosion productand can form in CO2-containing water with a very lowferrous ion concentration. Increasing the ferrous ionconcentration makes this film more protective, slow-ing down the corrosion rate by about an order ofmagnitude and possibly more after long expo-sures.25,35,55,77,83 Carbon steels protected by this trans-parent film can be susceptible to crevice and chloridepitting corrosion in a similar manner to passivatedstainless steels.44,56,72,83 Auger electron spectroscopyshowed that this film did not contain carbonate, butrather iron and oxygen ions roughly in the proportionof 1:2. Etching indicated a constant ratio betweeniron and oxygen in the full thickness of the film.83 Itis important to examine this film in view of the con-troversy on the existence of metastable solid FeCO3

56

and the well-known dehydration of FeOOH in thesteps leading to the classical passivation of iron.84 Asthese observations were not repeated, it is now ques-

usuario

Resaltado

usuario

Resaltado



firm or otherwise invalidate its formation and its ef-fect on FeCO3 formation.

Iron Carbide—Cementite (Fe3C) Films — Anodicdissolution of carbon steel leads to the formation ofdissolved ferrous ions. This process leaves behindsome uncorroded Fe3C film (cementite) that accumu-lates at the surface. Unlike FeCO3 scale, the Fe3Cfilm can be fragile and porous and therefore suscep-tible to flow conditions,6 or it can be a tough cement-ite network similar to “graphitization” of pig ironin acidic waters.58 A tough cementite layer adjacentto gouges caused by wire line runs is shown inFigure 7.27 At fast flow rates in unbuffered CO2-containing water, the corrosion film consists mainlyof Fe3C plus constituents of some alloying elementsfrom the substrate. A reduction of the flow rate mayincrease the amount of Fe3C, but it also leads to thepresence of FeCO3 in the film.28-29,31,35 Figure 8 showsan overview of a pure Fe3C film referred to as “emptycementite.”72

An empty cementite network forms a conductiveporous sponge layer on which the cathodic reactioncan take place. It is very adherent, with a metallic toblack appearance. Its thickness is up to 100 µmwhen formed under laboratory conditions19 and milli-meters in the field.27 The morphology shown in Fig-ure 9 was thus observed at the region of an unliftedwater slug at the bottom of a gas well in Nigeria invery agitated fluid conditions.27 This shows nonpro-tective tubercules of profuse FeCO3 deposits above athick base of empty cementite.

Fe3C film significantly affects the corrosion pro-cess and increases the corrosion rate by a factor of3 to 10 by playing a number of roles, including:

—Galvanic coupling: Fe3C has a much loweroverpotential for the cathodic reactions thaniron and thus galvanic contact between the twocan accelerate the dissolution of iron by accel-erating the cathodic reaction in the presence of<<1 ppm Fe2+ in water.25,72,77

TABLE 2Characteristics of Corrosion Films

Corrosion Temperature Range Characteristics/ Growth HabitFilm Class of Formation (°C) Nature and Composition

Transparent Forms at room <1 µm thick, transparent— Forming fast as temperaturetemperature and once formed, it is very reduces to < room temperaturebelow protective mainly consisting of Fe and oxygen

Iron carbide No range <100 µm thick, metallic, Spongy and brittle, consistingconductive, and nonadherent of Fe and C

Iron carbonate Min. required in laboratory Adherent, protective, and Cubic morphology, consistingconditions 50°C to 70°C nonconductive of Fe, C, and O

Iron carbonate Maximum 150°C All depends on how FeCO3 is Consisting of ferrous carbide+ iron carbide (higher temperatures blended with Fe3C and ferrous carbonate

not studied)

tionable whether this O/Fe ratio of 2:1 actually cor-responded to FeII or FeIII.58

Transparent films have been ignored by manyresearchers and a systematic study is needed to con-

FIGURE 7. A pure iron carbide layer formed at 60°C and 1 to3 times supersaturation.72

FIGURE 8. An overview of corrosion layers seen on a tubular showinga tough, empty cementite layer adjacent to gouges caused by wireline runs (courtesy of J.L. Crolet).

usuario

Resaltado



—Local acidification: Cathodic reactions can takeplace preferentially at Fe3C sites, thus physi-cally separating the anodic and cathodic corro-sion reactions. This leads to changes in thewater composition with the aqueous phase atcathodic regions becoming more alkaline andthat at the anodic sites more acidic.18-19,25,27,72,77

This can cause internal localized acidificationand promote corrosion on the metal surface.

—Fe2+ Enrichment: Having left behind the car-bide layer, ferrous ions dissolving at the metalsurface diffuses over a larger distance, so thatthe continuous concentration gradient neces-sary for this diffusion ends in a larger Fe++ en-richment at the metal surface. This increaseslocal supersaturation of ferrous ions and facili-tates the formation of FeCO3.

—Film Anchoring: In certain conditions, corro-sion film consists of a combination of Fe3C andFeCO3. In these films, Fe3C acts as a frame-work anchoring the precipitated FeCO3 on thesurface-enhancing film properties with im-proved tolerance to mechanical shear at highflow rates. In these situations, localized corro-sion is greatly reduced.38,79,83

Despite a high concentration of ferrous ions,local acidification at the surface may lead to unfavor-able conditions for the precipitation of FeCO3.

19,25,56,77,82

This may lead to FeCO3 precipitating within or on thetop of the cementite layer. This type of film forms ei-ther a corrosion layer with poor contact and bondingto the metal surface or with unfilled regions betweenmetal surface and the corrosion film. This corrosionfilm provides little protection, so corrosion rates canbe high. A local high corrosion rate tends to increasethe local pH difference between adjacent anodic andcathodic regions, which subsequently favors furtherdevelopment of the nonprotective film.19,25,72,79,82

In general, the accumulation of Fe3C has a con-trasting role on corrosion behavior, depending on itsmanner of formation and its dominance within thefilm structure and process. On one hand, by prevent-ing the diffusion of ferrous ions from the surface, itpromotes the formation of FeCO3 film to offer a de-gree of protection. By blending uniformly into FeCO3

film, it will enhance its properties and protectiveness,as described in the following section. On the otherhand, Fe3C could provide local acidification andfacilitate galvanic corrosion and hence increased rateof attack. Invariably, steel microstructure governscarbide distribution, which thus affects film stabilityor instability. This has been postulated to governcorrosion behavior as described elsewhere in the pa-per (Alloying Elements Section44,80).

Iron Carbonate—Siderite (FeCO3) Films — Interms of corrosion mitigation, FeCO3 or siderite is themost important film that can grow on carbon steelsin sweet environments. Film formation is strongly

dependent on the thermodynamics and kinetics ofFeCO3 precipitation. Supersaturation plays the mostimportant role in FeCO3 film growth and its morphol-ogy. A high supersaturation of FeCO3 is necessary toform a protective film, particularly at low tempera-tures.41,72 In principle, the precipitation process com-prises two steps, nucleation and particle growth. Themorphology of the film therefore depends on thedominating step.72,77 Once the film is formed, how-ever, it will remain protective at a much lower super-saturation.41 Protective film formation is acceleratedby measures that restrict the transport of reactionproducts from the surface.72

The adherence and thickness of the FeCO3 scaledepend on the metal microstructure.8-9 The scalegrown on normalized steels with a pearlitic/ferriticmicrostructure was more adherent, having largercrystals more densely packed and thicker than thoseformed on quenched and tempered steels.85 This isexplained further in the following section.

FeCO3 reduces the corrosion rate by reducingand virtually sealing film porosity. With altering nei-ther the local phase compositions nor the concentra-tion gradient, this restricts the diffusion fluxes of thespecies involved in the electrochemical reactions.Moreover, even prior to sealing cementite, its precipi-tation can lead to coverage and, therefore, can limitits electrochemical activity. This is explained furtherin the section on operating temperatures. All authorsagree that increasing the temperature would improvethe protectiveness of the FeCO3 scale as well as itsadhesion and hardness35 and that the higher thetemperature, the more improved the protectiveness.However, there is little agreement on a practical“threshold” temperature. Some have reported thatthe maximum corrosion rate observed for carbonsteel in sweet environments was from 60°C to 70°Cand then it started to decline due to growth of protec-tive FeCO3 films.86-87 In another work,35 it has beensuggested that the lowest temperature necessary toobtain FeCO3 films that would reduce the corrosion

FIGURE 9. Iron carbide layer forming on the metal surface followedby partial siderite sealing leading to a nonprotective film.56

usuario

Resaltado



rate significantly was 50°C and the protectivenesswas increased also by increasing the pH.

It has been argued that the protective filmsformed at higher temperatures and pressures pro-vided better protection than those formed at low tem-peratures and pressures. The level of protectionincreased with exposure time,88 which is the timedependency of the process.

Some key environmental parameters that influ-ence the iron carbonate film formation/precipitationare described here.

—Temperature Effect: As mentioned earlier,growth of FeCO3 scale is a slow temperature-depen-dent process.41,46 It has been reported that FeCO3

scale was more protective at higher temperatures(60°C to 100°C) with little protection at lower tem-peratures6,33,89 (<60°C) with Fe3C predominating thefilm. Above 100°C, a tight and adherent film wasformed with suggestions6 that magnetite was thestable scale above 121°C and the dominant scale at250°C,90 although magnetite has not been detected infield conditions. An increased precipitation rate athigh temperatures (>60°C) could explain why thecorrosion rate went through a maximum in the tem-perature range from 60°C to 90°C.

—pH Effect: pH is the most important factor inFeCO3 scale formation. It influences the solubility ofFeCO3, and, under suitable conditions, increasingpH decreases the FeCO3 solubility and promotes itsprecipitation in the environment, resulting in lowercorrosion rates. In CO2-saturated environments, for-mation of FeCO3 would decrease the corrosion rateby diminishing the diffusion of reactive speciesthrough the precipitated FeCO3 film.33,41,91 The pH in-crease also improves the protective properties of theFeCO3. Videm and Dugstad35 reported that at pH6.00 good protection could be obtained by FeCO3

films even at room temperature. In a related work,they demonstrated that an increase in pH also madefilm formation more likely as a result of a reductionin the solubility of Fe2+.83 Similarly, de Moraes, etal.,92 reported that protective layers could be ob-served only for pH values >5—very protective layerswere present only at high temperatures (93°C) andhigh pH values (pH ≥ 5.5), although these results arenow disputed.18

—Fe2+ Concentration Effect: Siderite formationoccurs in conditions where the concentration of Fe2+

ions in the aqueous phase exceeds the solubilityrange of FeCO3, bearing in mind that other speciesalso influence this process. It is also noteworthy thatthere are indeed two corrosion products, namely Fe++,resulting from the anodic reaction and HCO3

–, fromthe cathodic reaction.27 In uniform corrosion, theyare released consistently so that different concentra-tions of released ferrous ions also correspond to dif-ferent concentrations of released bicarbonate, whichwill lead to local changes in pH.27,29 A ferrous ion

concentration well below the solubility limit of FeCO3

not only prevented the formation of FeCO3-containingfilms, but also dissolved the existing films.35,81 Videmand Dugstad28 concluded that a change of 30 ppmFe2+ can sometimes affect the corrosion rate to thesame degree as a change in CO2 concentration of1,000 ppm (2 bar) at 90°C.

—H2S Effect: In the presence of both H2S andCO2, simplified calculations indicate that iron sulfidemay constitute the corrosion product layer when theH2S/CO2 ratio exceeds about 1/5,000—sour systemsconsiderations then would be expected to apply.93

Occasionally, it has been reported94 that the corro-sion product film formed under these conditions(containing FeS or Fe2S depending upon the H2S par-tial pressure) was apparently more protective thanFeCO3. The opposite also has been reported, espe-cially at very low H2S concentrations, wherein a mix-ture of layers forms comprising inner carbonate andouter sulfide.95-96

Iron Carbonate (FeCO3) Plus Iron Carbide (Fe3C)Films — This type of film is the most common filmfound on carbon and low-alloy steel surfaces in CO2-containing environments. During CO2 corrosion ofcarbon steels, the Fe3C phase is cathodic (corrosionresistant) and may embed within the FeCO3 film. Thestructure of the film then will depend on where andwhen the FeCO3 precipitation takes place. On onehand, if it occurs directly and integrates within thecarbide phase, then a protective and stable film willform that often can stand high fluid flow conditions.On the other hand, initial formation of a cementitelayer on the surface followed by partial FeCO3 sealingclose to or beyond the external limit of cementite canlead to a nonprotective film. An example of this isshown in Figure 10.25,27,72 In contrast, if cementitephase effectively sealed the siderite layer formed incontact with the metal surface, an incomplete sealingor a partial redissolution of FeCO3 anywhere else isnot detrimental and the corrosion film remains pro-tective, as shown in Figure 11.25,27,72

Crolet, et al.,25 have categorized the morphologiesof corrosion film formation as affecting protective-ness. This is shown in a simplified diagram in Figure12. The diagram is based on an analysis of the diffu-sion/precipitation issues and the resulting pH shifts,and is backed by observations of the actual mor-phologies of protective and nonprotective corrosionlayers.

As mentioned earlier, the structure of the mixedfilm plays an important role on the formation andbreakdown of protective carbonate films. This is in-fluenced by the carbon content and the size and dis-tribution of carbides, which therefore is dependent ofthe microstructure of steel.85 The ferritic-pearliticsteels have a carbide structure, which gives a goodframework for the buildup of protective carbonatefilms.79 Quenched and tempered steels and ferritic

usuario

Resaltado

usuario

Resaltado

usuario

Resaltado

usuario

Resaltado

usuario

Resaltado

usuario

Resaltado



steels with low carbon content have a finely distrib-uted carbide structure that does not give an inte-grated framework to anchor and enhance theformation of protective carbonate films.32,38,77,79 Ex-

periments with the plain carbon steel after differentheat treatments showed that both corrosion rate andthe ability to form protective films decreases with in-creasing tempering temperature, indicating that thecarbide structure of the steel plays an important rolefor the formation of protective corrosion films.77

As mentioned earlier, it is likely that Fe3C lamel-lae at the metal/corrosion film interface can anchorthe film and contribute to corrosion protection.27,35,79

This anchoring effect of the carbide phase is believedto be the main factor influencing the adhesion of theFeCO3 film to the surface and has been reported bymany workers.9,33,55,77,79

Film Breakdown and Localized CorrosionA sensitive balance between the formation and

destruction of the protective film governs the subse-quent corrosion progress and determines whetheruniform or localized attack will take place.30

Mesa attack can be initiated by local breakdownof the protective film or by the growth of pits beneath

FIGURE 11. A cementite layer sealed by siderite forming a protectivefilm.25,72

FIGURE 10. An empty, thick, and porous cementite network formedon tubing recovered from the field, which was covered by a porousbut hard and mechanically resisting siderite tubercule (courtesy ofJ.L. Crolet27).

FIGURE 12. Different morphologies observed for protective andnonprotective corrosion layers (after Crolet, et al.25).



the porous corrosion film by a local cell mechanism.The remaining corrosion film on top is removedstepwise by the turbulent flow before the pit can con-tinue to grow into a larger mesa attack. When thefilm has been torn away in one area, the corrosionattack continues further beneath the film close to theedge until another piece of the film is removed. It isassumed that a galvanic cell is set up between theanodic, film-free metal in the bottom of the mesa at-tack and the cathodic, film-covered metal outside themesa attack, leading to a high corrosion rate in thebase of the mesa-attacked area.33,43,97

Enhancement in the formation of protective filmsaffects the corrosion rate in the base of the mesa byenabling the formation of carbonate films, which canthen stop further growth of the mesa attack. Shallowmesa attack covered with corrosion films have beenfound in experiments on precorroded samples, andlinear polarization resistance (LPR) measurementshave shown that the growth of this mesa attackslows down gradually during the experiment andeventually stops. This shows that reformation of pro-tective films in mesa-attacked areas is possible whenthe growth rate of the mesa attack is not toohigh.31,41,72 With a better quality of the initial protec-tive films, the effect of galvanic coupling between themesa-attacked area and the surrounding area withintact corrosion films can be smaller, resulting in aslower and less catastrophic mesa attack. Rate ofgrowth at mesa-attacked areas has been shown to beexcessively higher than the adjacent unattacked ar-eas, reaching some 20 mm/y to 30 mm/y in waterwith around 2 bar CO2, pH 5.5 to 5.8, and 3% NaClat 80°C.31,41,72,97 In laboratory tests, mesa attack oc-curred under these conditions at a flow rate of 7 m/sbut not below 2.5 m/s. Low-chromium-containingsteels (0.5% to 1% Cr) did not suffer deep mesa at-tack under these conditions.97

Fluid Flow Effects — The effect of flow rate on thecorrosion rate originates primarily from localizedflow-induced changes introduced by the corrosionfilm. Fe3C particles remaining on the surface, theFeCO3 buildup, and the accumulation of alloying ele-ments in the corrosion film are flow-dependent phe-nomena.30 As mentioned earlier, a clear distinctionshould be made between pure CO2 corrosion and acombined interaction of erosion-CO2 corrosion.

Flow rate of water containing CO2 has two princi-pal effects on film formation and corrosion rate andform. First, it prevents the formation and slows downits growth by reducing the local supersaturation.Second, flow can damage film locally to cause local-ized corrosion, especially mesa attack. When the sur-face corrosion film is poorly adherent to the surface,the effect of flow rate on localized corrosion is mostserious.47,69

In low-temperature conditions from 30°C to60°C, films might not form or might not become pro-

tective for a long period in continuous flow loop ex-periments. This therefore could lead to fast uniformcorrosion, although protective films can form at thesetemperatures when water stagnation on steel isprevalent.70,83

In the presence of solids (sand), erosion-corro-sion can produce higher wall penetration rates thanerosion or corrosion alone. Three typical behaviorshave been found. At low velocities, a protective FeCO3

scale formed over all surfaces of an elbow, and corro-sion rates were very low. At high velocities, impinge-ment on elbow surfaces by sand particles entrainedin the flow prevented protective layers forming in theelbow. Corrosion rates were high and uniform overthe entire surface. At intermediate velocities, protec-tive layers formed over the entire elbow surface, ex-cept at very localized points where impinging sandparticles prevented scale formation. Deep pits formedat these locations and wall penetration rates wereextremely high. These conditions are damaging butcan be avoided by reducing or increasing flow veloci-ties. A computational model for the prediction ofsand erosion in piping systems was used to simulateexperiments to explain the three observed behaviorsand predict conditions defining boundaries betweenthem.98

Siderite (FeCO3) formed only in low-velocity,single-phase flows where pH increased above 5.0.Corrosion rates after scale formation decreased byalmost 1 order of magnitude. No FeCO3 scale formedin tests involving high-velocity, low-pH, single-phaseflows or two-phase flows.85

In fact, at medium or high pH conditions, protec-tive films always form unless the following param-eters are met conjointly in laboratory testing:58

—initial bare surface—room temperature—uninterrupted high flow rate from the start of

the testIn the absence of each, films do form and be-

come protective and their protectiveness remains un-affected by flow. This basic irreversibility of corrosionlayers82 explains the reported temperature effect,which essentially appears as a laboratory artifact andmost unexplained good performance of the film expe-rienced in real field conditions, which can be the re-sult of inevitable shutdown periods.58

The influence of solid particles (sand) and theirinteractions with flow-induced corrosion is not fullyunderstood, and predictive models do not includecorrosion-enhanced erosion by solids.

Iron Carbonate/Siderite (FeCO3) Scale:Recent Progress

The significance of steel characteristics and envi-ronmental variables on the protective nature ofFeCO3 (siderite) corrosion films was emphasized ear-lier. A recent study has demonstrated the intricacy of

usuario

Resaltado



how corrosion protection offered by a precipitatedFeCO3 scale on carbon steel substrate can be im-proved through varying or adjusting some of the en-vironmental parameters such as pH, temperature,solution composition, and periodic exposure to air.99

Among these, pH was shown to be the most influen-tial variable in affecting the precipitation of FeCO3.

The key factor preventing the growth of a protec-tive siderite scale was that the nucleation and growthof crystals of this compound were extremely tempera-ture sensitive and slow with a rather high activationenergy, confirming an earlier indication by others.46

In this respect, for siderite as well as calcite andother forms of calcium carbonates, the limits of thedomain of precipitation are not driven by saturation(thermodynamic stability) but by supersaturation(kinetics). Also, it is worth noting that scaling inhibi-tion is crystal specific and there was an indicationthat some scale inhibitors could prevent the forma-tion of calcium carbonate but not siderite.99

Key points of observation emerging from thiswork on corrosion films/layers formed under sider-ite-forming conditions (pH range from 5.60 to 6.30,75°C, and 1 bar CO2 pressure) are highlighted:90

—The film consisted primarily of FeCO3 and re-sembled a perfect cubic morphology (bearingin mind that siderite is a rhombohedric crys-

tal) as shown in Figure 13 as also previouslyseen by others.41

—The film was a few micrometers thick andformed just after 24 h immersion. Scale thick-ness, as measured by a scanning electron mi-croscope (SEM), increased progressively withtime, becoming more compact (Figure 14). Sid-erite “cube” dimensions play an important rolehere, as suggested by others,8,18,27 in affordingfurther protection by hindering the ingress ofcorrosive species toward the metal substrate. Itshould be noted that the key issue of the liquidsurface state has not been observed by SEM.

—Periodic exposure to the atmosphere, or moreprecisely to oxygen (through removal and re-exposure of samples), improved significantlythe scale adhesion to the substrate.

—The work reiterated that FeCO3 precipitationcoincided with a sudden drop in weight changeand its associated corrosion rate.

—Similar immersion tests conducted with pureiron (99.5%) samples produced a patchy,cracked, and loosely adherent FeCO3 scale.This was attributed to the absence of a carbidenetwork in pure iron.

—Solution chemistry played an important role inaltering the protective characteristics of the

FIGURE 13. Iron carbonate scale precipitated on carbon steelsamples at 75°C exposed to a solution at pH 6.30 at 1 bar CO2

showing a somewhat cubic appearance (magnification: X6,000).99

FIGURE 14. Iron carbonate scale formed after 260 h of immersionin a solution (at pH 6.30, 75°C, and 1 bar CO2) showing a compactappearance.99



precipitating FeCO3 scale. In these series oftests, scales developed in distilled water wereless adherent to the substrate than those de-veloped in a solution containing trace Mg2+

ions simulating produced fluid chemistry, andMg2+ ions improved siderite scale protectionand adhesion. However, magnesium-relatedtrends have not been observed in field evalua-tions.14,36

—The nucleation and growth of FeCO3 crystalswas a slow, temperature-dependent process;consequently, any environmental changes thatretarded the precipitation process therefore ledto progressively increased corrosion.

The work highlighted that the terms “protective-ness” or “corrosion-resistant properties” of a scalewere loosely defined definitions. Therefore, the pro-tective characteristics of FeCO3 scale were translatedthrough the following specific properties allowingbetter characterization:

—scale density (or, in other words, pore distribu-tion in the scale)

—adhesion—stability—surface coverageBased on this, the effect of various environmen-

tal parameters affecting scale characterization andprotectiveness have been tabulated. These are sum-marized in Table 3, demonstrating that solution pHis the most influential parameter in the precipitationof FeCO3 scale and seemingly the only parameterthat affects scale density.99 The work of Nesic, et al.,has led to modeling of the possibility of predicting theinfluence of FeCO3 film.20

CORROSIVITY

As a general statement, the corrosivity of theaqueous phase will be dependent on CO2 partialpressure, temperature, solution chemistry, and in-situ pH. On one hand, at a given partial pressure ofCO2, condensed waters (associated with gas produc-

tion) are in general more corrosive than formationwaters since they do not contain any buffering orscale-forming species and inherently have a lower in-situ pH. On the other hand, at a given pH, the simplechemistry of condensed water at low CO2 partialpressures may be less corrosive than some complexchemistries of reservoir water under higher CO2

partial pressures.27

Software and spreadsheet-based programs nowexist for characterizing water chemistry such thatconcentrations of dissolved species and solution pHcan be readily calculated.36,100-104 Nevertheless, the oiland gas industry has grown up assessing the pres-ence of dissolved CO2 in water in terms of CO2 partialpressure. This simply derives from the application ofHenry’s Law for a gas in equilibrium with a liquidand the approximation of ideality, where the thermo-dynamic activity of CO2 in water is assessed throughits partial pressure in the gas. This remains validup to high CO2 partial pressures, particularly on alogarithmic pressure scale, which is that related topH variations.

Viewing it starting from reservoir conditioning,Crolet and Bonis14,36,55,105 consider variations in CO2

concentration resulting simply from differences inthe solubilities and activity coefficients in the phasespresent. Thus, for example, in three-phase produc-tion, which is generally highly turbulent, eventhough the CO2 equilibrium is never perfect, anydeviations remain relatively insignificant. Conse-quently, it is more reasonable, and certainly mucheasier, to express the amount of CO2, not in terms ofits concentration in each phase, but as its “chemicalpotential” (or thermodynamic activity or fugacity).Provided conditions are not close to the gas liquefac-tion point, this is simply equivalent to the partialpressure of CO2 in the gas phase. By extrapolation,reference then can be made to CO2 partial pressureeven in systems where there is no free gas phasepresent. Experimentally, this “virtual partial pres-sure” corresponds to the real partial pressure of CO2,which would appear in the nascent gas phase if thesystem were to be depressurized. At the bottom of anoil well, this “virtual partial pressure” will be the veryfirst bubble at the “bubble pressure” of the reservoirfluid; in a gas free line downstream of the gas sepa-rator, this will be the partial pressure at the last gasin the separator.18

Variations of dissolved CO2 along the flow linewill affect the solubility of potential scaling com-pounds, particularly CaCO3, which can interfere withthe corrosion process and possibly its inhibition, ifprecipitated. The in-situ pH level can also affect thesolubility of ferrous oxides and hydroxides, increas-ing their solubility with decreasing pH. However, ofparticular importance are conditions that favor depo-sition of FeCO3 (siderite). Formation of FeCO3 servesto complicate the picture further, as it can, under

TABLE 3Effect of Various Parameters on Scale Protectiveness99

SurfaceParameter Coverage Stability Adhesion Density

Oxygen — * * —Magnesium — * * —Temperature * — * —pH * — * *Carbide phase — * * —

* Improvement in certain characteristics of the scale.— No improvement was observed.Note: Stability should not be confused with adhesion. Stability meansthe endurance of the scale toward environmental variables like solutionpH and flow velocity.



certain conditions, passivate the corrosion reactionmaking it even more difficult to accurately predictcorrosion rates.58

CO2 CORROSION PREDICTION

Over the years much effort has been expended instudying factors controlling the performance of mate-rials in production environments in an attempt todefine the safe operating limits of candidate materialsin terms of the environmental and mechanical condi-tions. This knowledge is gained, in part, from somecomprehensive, empirical-based field statistics, suchas those by API,7,68,106 laboratory-based informationtranslated by quantitative regression to predictive acorrosion rate,9,91,100-104 and comprehensive well sta-tistics based upon the actual field values of relevantscientific quantities.36,105

The laboratory-based equations have been con-ventionally based using the de Waard and Milliamsnomogram.9,96-97,100 Nonetheless, in the past, it wasimperative that candidate materials were assessedin the laboratory prior to their application in the fieldso that costly and potentially hazardous failures areavoided. However, the relevance of some of theseshort-term tests to long-term performance was ex-ceedingly difficult to establish other than by long-term experience or evaluation.

The inherent corrosivity of acidic gases has longbeen recognized and has prompted extensive studiesof the subject.6-9,100 These have led to the develop-ment of predictive models or criteria that attempt tocorrelate corrosion to acidic gas partial pressure.However, in merely using these predictive models,there is a danger of working with a too simplistic orclear-cut picture of the situation. Any predictionsthat are made are not only influenced by the validityof the model, but also the quality and reliability ofthe supplied production and operational data used tocalculate the corrosion risk.

The engineer ideally wants a predictive tool thatcan be readily applied and is suitable for applicationat all stages of project development and subsequentoperation. This may seem a tall order but it maynevertheless be argued that the fundamentals of theCO2 corrosion process will be common to all situa-tions; it is the overlying effects of such factors asflow regime, film formation/deposition, hydrocarbonphase, realistic and representative testing, steelchemistry, and corrosion inhibitor that cloud or com-plicate the picture.

A true industry standard approach to predictingCO2 corrosion does not exist, although there areaspects of commonality between the various ap-proaches/models in use by the industry. There is noprofessional body or agency such as NACE Interna-tional providing standard basic guidelines to workfrom—unlike the situation for H2S.81,107-108 While it

may be argued that such guidelines, because of thecomplexity of the problem, would either be too gener-alized and/or too conservative for certain situations,their presence nevertheless would have a unifyinginfluence to a degree and at least provide a commonreference point from which to work.

Having determined the water chemistry, thisthen needs to be translated into a corrosion risk,preferably expressed quantitatively as a rate and typeof attack. The easiest parameter to relate to (and ingeneral, measure) experimentally and in the field isthe partial pressure of CO2. Thus, over the years, anumber of empirical relationships have evolved withvarying levels of complexity and theoretical sub-stance. In the simplest form, API7 in the late 1950sprovided a “Rule of Thumb” criteria for carbon andlow-alloy steels. After a first period of high popular-ity, this rule endured several exceptions and fell intooblivion with just periodic quotes, such as that byMudge and Levesque,109 who cite the following “Ruleof Thumb” criteria for carbon and low-alloy steels, orthe complementary note from Crolet:18

—PCO2 < 0.5 bar (7 psi)

Corrosion Unlikely: implying that corrosion isuniform and the rate is <0.1 mm/y

—0.5 bar (7 psi) < PCO2 < 2 bar (30 psi)Corrosion Possible: implying that corrosion ratemight be between 0.1 mm/y to 1 mm/y anddesign consideration is based on life expectancy

—PCO2 > 2 bar (30 psi)

Corrosion likely: implying that corrosion ratemay exceed 1 mm/y, which is unacceptable

where partial pressure of CO2 is denoted as PCO2

These are based on field experience, principallyin the U.S. No subsequent standard guidelines existas to the courses of action necessary for each condi-tion, although experience will trigger the corrosionengineer to look initially toward certain possible op-tions (e.g., use of a corrosion inhibitor or more corro-sion-resistant alloys). However, designing on such abasis is not a very satisfactory way to operate.

Rules of thumb may be viewed as:—an aid to first-pass materials selection—offering qualitative and generalized assessmentMore specific questions on service life, risk

analysis, corrosion allowance, and inhibited corro-sion rates require the ability to conduct a quantita-tive assessment (i.e., the ability to predict corrosionrates for a given set of conditions). In addition, con-sequence of corrosion is a key issue when corrosivityassessment is carried out. Nevertheless, the relation-ship between corrosion rate and CO2 partial pressurehas formed the basis of a number of predictive mod-els/equations for carbon steels, even though claimshave been made that PCO2

bears little relation to thedecision by the field operator.110

Experimental work has lead to a number ofequations or models being developed relating corro-

usuario

Resaltado



sion rate of carbon and low-alloy steels to CO2 partialpressure,11,36,91,94,100-104,111 from which individual op-erators have each developed their own approach orphilosophy.

Most equations or models have been derivedfrom a range of experimental conditions. For ex-ample, the de Waard and Milliams equation or nomo-gram11 was originally derived for a 0.1% NaClsolution test medium at a flow velocity of ca. 1 m/s,temperatures up to 80°C, and PCO2 up to 1 bar forX52 C-steel. Greco and Wright94 used 0.04% NaClsolution at 86°F and PCO2

up to 4.5 bar; Videm andDugstad28 used distilled water, up to 120°C, 6.5 barPCO2

, and 20 m/s flow velocity. The models developedby Fang, et al.,102 and Liu and Erbar104 are based ontheoretical analysis together with the use of datataken from the literature—both of these models werespecifically developed for gas well corrosion.

While the use of simple NaCl brine might eventu-ally mimic water in gas systems, when consideringbrines co-produced with crude oil, their water chem-istries are far more complex and their influence (buff-ering) thus needs to be corrected when using theseequations. Many parameters, such as temperature,pH, partial pressures of CO2 and H2S, gas/oil ratio(GOR) and water production (water/oil ratio—WOR),water composition, together with flow rate and re-gime, have a greater or lesser effect on the corrosionrate. Furthermore, not all of these parameters areindependent of each other, pH being a good example.8-9

Finally, direct field validation of the predictedcorrosion rates often is difficult to unequivocally sub-stantiate. This is particularly true when a modelneeds detailed data, which are seldom gathered inthe field. Furthermore, these data are not totally de-fined throughout the service life of equipment.18

Several prediction models for CO2 corrosion of oiland gas pipelines are available. These models havevery different approaches in accounting for oil wet-ting and the effect of protective corrosion films, andthis accounts for much of the differences in behaviorbetween the models. All the models are capable ofpredicting the high corrosion rates found in systemswith low pH and moderate temperature, while themodels can predict quite different results for situa-tions at high temperature and high pH, where protec-tive corrosion films may form. An overview ofcapabilities and shortfalls of the available models hasbeen provided by Nyborg100 and is also summarizedin EFC Publication 23.9

An intermediate approach that places direct em-phasis on knowledge of the water chemistry is theprediction tool developed by Crolet and Bonis.36,105

This tool is an “advanced” field database that calcu-lates the factual input data, especially pH, free HAc,and potential corrosivity, in terms of corrosion riskfor the occurrence of failure within the life of thewell. It defines the severity of CO2 corrosion in wells

in terms of “low” and “high” risk as a function ofworkover statistics, plus a “medium” category forborderline or undocumented conditions. Crolet andBonis compared these with all the basic informationavailable at the time, combining both field experi-ences and laboratory data. Key parameters includedin this multiple correlation were the “potential corro-sivity” (what is observed in the laboratory on baresurfaces but just taken as an index of electrochemi-cal reactivity and in no way a corrosion rate predic-tion) and the field features (in-situ pH, Ca2+/HCO3

–

ratio, concentration of dissolved organic acids[mainly HAc], and, to a lesser extent, flow velocity).This tool expresses two distinctive tables indicatingcorrosion risks, one for oil-producing wells and onefor the gas-producing wells. It complements the APIrules7 and explains their exceptions; notably thatCO2 corrosion is indeed ubiquitous at high PCO2

andit progressively disappears at low PCO2

, unless H2CO3

is supplemented by free organic acids and the “CO2

corrosion” by “HAc corrosion.”19,27,81 This, to a greatdeal, concludes the original debates launched in19447-8,19,106 on the concept of damaging mechanismscaused by either CO2 or organic acids when the firstdecision was made in 1958 in favor of a CO2-onlymechanism7 followed by the origin of the great manyexceptions to the API rules.7,106

Industry PracticeWhile an industry standard approach to predict

CO2 corrosion damage does not exist per se, the workof Shell8-9,11,91,101 in this area has provided a strongreference statement from or against which to work.The de Waard and Milliams equation or nomogramhas been developed as an engineering tool. It pre-sents in a simple form the relationship between “po-tential corrosivity” (worst case) of aqueous media fora given level of dissolved CO2, defined by its partialpressure at a given temperature.

The current form of the basic Shell equation isas follows:8-9,91,101,112

1 1 1/ / /V V Vcor r m= + (8)

log( ) . – , / ( ) . log( ) –

. ( – )

V t P

pH pH

r CO

actual CO

= + +5 07 1119 273 0 58

0 342

2

(9)

V V diam Pm liq CO= 2 7 08 0 22

. ( / ). (10)

where Vcor is the corrosion rate (mm/y); Vr and Vm

represent the maximum kinetic reaction and mass-transfer rates, respectively; t is temperature (°C),PCO2

is partial pressure of CO2; pHactual is the actualpH; pHCO2

is pH resulting from CO2 only; Vliq is liquidvelocity (m/s); and diam is the hydraulic diameter(m). The important influence of temperature on CO2

corrosion is depicted in Figure 15.8,112



There are appropriate correction factors for gasfugacity, corrosion scales/surface films (i.e., Fe3O4

and/or FeCO3), the influence of flow (mass-transfereffects), and steel composition. Correlation with fieldexperience suggests that the de Waard approach gen-erally predicts the worst-case corrosion rate. The cor-rection factors for pH and scale (scale factor appliedat temperatures > 60°C) are simplified versions, butthey nevertheless appear suitable for many applica-tions, especially for formation waters.

The relative simplicity of the de Waard andMilliams approach and its ease of use have undoubt-edly been positive factors in its broad acceptance,although its complexity has grown over the years asbetter appreciation of the CO2 corrosion process andinfluence of water chemistry have evolved togetherwith correlation with field experience.36,100,103,111

There would appear to be a trade-off between amodel’s relative ease of use vs availability, detail, andreliability/accuracy of necessary input data/condi-tions vs degree of accuracy/absoluteness required ofthe assessment of the corrosion risk. The latter willalso be influenced by the ease and sensitivity of sub-sequent corrosion monitoring and inspection.

On the other hand, the well database of Croletand Bonis36,105 also requires some tedious calcula-tions for the figures used as input in the correlation,and this is also made through a spreadsheet called“CORMED.” This may have given the false impressionthat CORMED is just a model like others, whereas itsgoal is to translate the analytical sheets of the rawfield data into the requested factual inputs (pH, freeHAc, etc.) and automatically compare them to theirrespective critical values in the published tables.CORMED places direct emphasis on knowledge of thewater chemistry and defines severity in terms of low,medium, or high risk. If early workovers in the first10-year period have been reported in similar condi-tions, it is concluded that the corrosion risk is re-spectively high or otherwise low. Considering that atubing is ~10 mm thick, this means that the averagecorrosion rate will be respectively above or below0.1 mm/y, which is precisely the information givenby conventional corrosion tables.

Both the de Waard and Milliams nomogram andCORMED approach have been developed from abasic consideration of the CO2 corrosion reactions—the former is more empirical in origin and the latteris more theoretical. Both have attempted to accountfor the overlying effects either by applying correctionfactors (de Waard and Milliams) or through field cor-relation (CORMED).

Finally, it is worth restating that all availablemodels/equations only apply to carbon and low-alloysteels and are not strictly valid in the presence of H2Sdue to formation of protective sulfide films, whichmay nevertheless be susceptible to localized break-down under long-term exposure.

EFC Publication 239 sets out a process for deter-mining CO2 corrosion risk/rate. In achieving this,a key element is the interaction between the corro-sion engineer and the petroleum engineer to ensurethat the service conditions are correctly defined andrelevant.

CO2 CORROSION CONTROL

The wide-ranging environmental conditions pre-vailing in the oil and gas industry necessitates theappropriate and cost-effective materials choice andcorrosion control measures. Corrosion can impose asignificant cost penalty on the choice of material atthe design stage, and its possible occurrence alsohas serious safety and environmental implications.Furthermore, as production conditions tend to be-come more corrosive, they require a more stringentcorrosion management strategy.

Corrosion control may be affected in a numberof ways, either singularly or in combination. In thecase of oil and gas production, the corrosion controlmethods include:

—change/modify operational parameters (e.g.,flow, temperature, remove water) or systemdesign (e.g., remove sharp bends, deadlegs,crevices)

—change/modify chemistry of the environment(e.g., remove O2 from any liquid reinjected inthe production flow, lower CO2 partial pres-sure, scavenge H2S, add corrosion inhibitor,increase pH)

—change/modify interfacial conditions of metal(surface modifications or possible implementa-tion of cathodic protection)

FIGURE 15. Effect of temperature on CO2 corrosion.8,112



—apply organic coating (e.g., fusion-bonded ep-oxy, phenolic-modified epoxy) or use a liner(e.g., polypropylene) to isolate metal from cor-rosive environment

—use more corrosion-resistant materials (e.g.,13% Cr steel, duplex stainless steels) either inthe solid form or as cladding on carbon steel

—use nonmetallics (e.g., fiber-reinforced plastics)The relative merits of each approach must be

viewed in the context of the application, the requiredservice life, and the severity of the conditions. Nohard and fast rules exist in a general sense, andmany decisions are made based on past experienceand individual preference. Clearly, each action is as-sociated with a cost that highlights the need for goodinitial design together with a sound understanding ofthe possible corrosion processes if cost-effective cor-rosion management is to be achieved without com-promising safety.

Finally, the value and importance of corrosionmonitoring and inspection should not be forgottenand goes hand-in-hand with the above for the mostpart and certainly where carbon and low-alloy steelsare used. In addition, the role of top-of-the-line cor-rosion needs specific attention.

Corrosion inhibitors are used extensivelythroughout the oil and gas industry offering, whereappropriate, a cost-effective means of corrosion con-trol, particularly for flowlines, pipelines, andtrunklines. For the most part they are used to inhibitthe reactivity of carbon and low-alloy steels contact-ing the aqueous phase co-produced with oil and gas.

TECHNOLOGY GAPS

This review has highlighted key areas of progressboth mechanistically and industrially based on whicha number of key messages recommending areas foradditional research has been drawn. These can leadto further the understanding of CO2 corrosionmechanisms to enable improved predictive capabili-ties for the effective use and deployment of carbonand low-alloy steel in oil and gas production. Notableareas of technology gap requiring systematic studiesinclude:

—CO2 corrosion testing: a complex procedureand a topic of ongoing investigation. There is agreat need to develop a field reproducible andconsistent procedure to evaluate CO2 corrosion.This should truly reproduce the known fieldobservation of corrosion damage from the worstcases to those providing adequate protectionand incorporate all key parametric sensitivities.

—Interaction of CO2 corrosion with H2S: the sig-nificance of H2S promoting or retarding corro-sion has received little due attention and isa major source of concern in designing newdevelopment.

—Presence of hydrocarbon phase: hydrocarbonplays a vital role in CO2 corrosion in terms ofits phase ratio, its partitioning capability forCO2, water wetting, and its inhibiting effect onCO2 corrosion. Further focused research tocharacterize the nature of hydrocarbon phasecan lead to better predicative capabilities.

—Steel chemistry: while major studies have ledto the development of carbon and low-alloysteels with superior resistance to CO2 corrosion,these require fine-tuning to produce steelswith inherent resistance to CO2 corrosion.

—Flow modeling: further emphasis on flow mod-eling to better quantify water wetting/sheddingcan lead to improved predictive modeling,bearing in mind flow regime and their changesthroughout the life of the field.

—Welds: the performance of welds and preferen-tial weld corrosion remain a major operationalobstacle, particularly in the absence of corro-sion inhibition. This subject has not been re-viewed in the present article and requiresfocused attention.

—HAc: while some recent work has discussedthe influential role of HAc, its role requiresfurther study to determine its complementaryeffect on CO2 corrosion.

—Siderite formation: siderite, when formed, of-fers superior protection. Studies on earlynucleation and growth of siderite can be ofsignificant benefit in corrosion mitigation.

—Erosion-corrosion: the presence of solids to in-duce erosion and its interaction with corrosionis poorly understood and the subject is in needof clarification to develop a conjoint erosion-corrosion model taking on board solid content.

CONCLUSIONS

� This overview article has led to a number of keyconclusions emphasizing the importance of the sub-ject in providing integrity management for oil and gasproduction facilities.� Corrosion failures account for 25% of all safetyincidents, 2.8% turnover, 2.2% tangible asset, 8.5%increase on capital expenditure, 5% of lost/deferredproduction, 11.5% increase to the lifting costs ormore quantitatively ca. 0.30 $/boe. The majority ofthese are associated with CO2 corrosion of carbonand low-alloy steels with implications on capital andoperational expenditures (CAPEX and OPEX) andhealth, safety, and the environment (HSE) and opera-tor dependency.� The industry continues to lean heavily on the ex-tended use of carbon and low-alloy steels, which arereadily available and are able to meet many of themechanical, structural, fabrication, and cost require-ments. Their technology is well developed and they

usuario

Resaltado

usuario

Resaltado

usuario

Resaltado

usuario

Resaltado

usuario

Resaltado

usuario

Resaltado

usuario

Resaltado

usuario

Resaltado

usuario

Resaltado

usuario

Resaltado



represent for many applications an economic materi-als choice. However, a key obstacle for their effectiveuse is their limited corrosion performance.� CO2 corrosion of carbon and low-alloy steel re-mains a complex phenomenon and, despite severalextensive studies over the past 4 decades, its mecha-nism, realistic predication, and control are in need ofbeing addressed effectively. Its understanding, pre-diction, and control remain key challenges to soundfacilities design, operation, and subsequent integrityassurance.� CO2 corrosion is influenced by a large number ofparameters, including environmental, physical, andmetallurgical variables. All parameters are interde-pendent and can interact in many ways to influenceCO2 corrosion.� Ignoring the corrosion problems associated withsour service, low levels of H2S can affect CO2 corro-sion in different ways, either complementing CO2 cor-rosion by acting as a weak acid or have a positiveeffect on sweet corrosion through the formation of aprotective sulfide scale.� Presence of HAc or, more generally, organic acidsreduces the protectiveness of the films and increasesthe sensitivity to mesa attack. This is attributed to alower Fe2+ supersaturation in the corrosion film andat the steel surface in the presence of organic acids.� Corrosion scales, when formed under certain con-ditions, can afford superior protection. While theirformation and growth have been the subject of manystudies, favorable conditions for the development of atruly protective film to provide subsequent effectiveprotection need further scrutiny.� Precipitation kinetics of FeCO3 is affected by theiron and carbonate concentrations, and its subse-quent formation and growth are extremely tempera-ture sensitive. These can be categorized as follows:

—At low temperature conditions (<75°C), growth isslow with consequent need for extremely longtesting to address it effectively

—At intermediate temperatures (75°C to 110°C),the precipitation reaction may influence corro-sion reactions since there is no requirement forsupersaturation

—At high temperatures (>110°C), FeCO3 precipita-tion is likely to be rapid and growth is diffusion-controlled. Iron released by the corrosionprocess therefore may re-precipitate immediatelyat the surfaces, providing a complete adherentprotective layer.

� Steel chemistry plays a significant role in provid-ing protection against CO2 corrosion and can lead tosubstantial economical gains.

ACKNOWLEDGMENTS

The authors acknowledge J.L. Crolet (formerlywith TotalFinaElf) for his significant input, help with

correcting errors, and addition of pertinent informa-tion. Helpful contributions of D. Harrop (BP), Y. Zhu(Windsor Scientific Ltd), and D. Williams (UniversityCollege London) are also acknowledged.

REFERENCES

1. M.B. Kermani, D. Harrop, “The Impact of Corrosion on the Oiland Gas Industry,” J. SPE Production Facilities 8 (1996), p.186-190.

2. M.B. Kermani, “Materials Optimization for Oil and Gas SourProduction,” CORROSION/2000, paper no. 156 (Houston, TX:NACE International, 2000).

3. P. McIntyre, Corrosion Management 46, 3/4 (2002): p. 19.4. M. Bonis, P. Thiam, “Measurement of Corrosion Costs within

Elf’s Exploration and Production,” Eurocorr 2000, Conf. Euro-pean Federation of Corrosion (London, U.K.: Institute of Mate-rials, 2000).

5. M.B. Kermani, D. Harrop, “Materials Selection for Oil and GasProduction and Transportation Facilities,” 3rd Int. Corros.Cong., held May 10-12 (Tehran, Iran: University of Tehran,1993).

6. R.H. Hausler, H.P. Gaddart, eds., Advances in CO2 Corrosion,vol. 1 (1985) and 2 (1986) (Houston, TX: NACE).

7. Corrosion of Oil and Gas Well Equipment (Dallas, TX: Ameri-can Petroleum Institute, 1958).

8. M.B. Kermani, L.M. Smith, eds., Predicting CO2 Corrosion inthe Oil and Gas Industry, European Federation of CorrosionPublication no. 13 (London, U.K.: Institue of Materials, 1994).

9. M.B. Kermani, L.M. Smith, eds., CO2 Corrosion Control in Oiland Gas Production—Design Considerations, European Fed-eration of Corrosion Publication no. 23 (London, U.K.: Institueof Materials, 1997).

10. W. Schwenk, Werst. Korros. 25 (1974): p. 643.11. C. de Waard, D. Milliams, Corrosion 31 (1975): p. 131.12. G.I. Ogundele, W.E. White, Corrosion 43 (1987): p. 665.13. D. Harrop, J.W. Martin, C.W. White, ASTM/NPL Symp. on

“Use of Synthetic Environments for Corrosion Testing”(Teddington, U.K.: National Physical Laboratory, 1986).

14. J.L. Crolet, M.R. Bonis, Corrosion 39 (1983): p. 39.15. G. Schmitt, “Fundamental Aspects of CO2 Corrosion,” COR-

ROSION/83, paper no. 43 (Houston, TX: NACE, 1983).16. G. Schmitt, S. Feinen, “Effect of Anions and Cations on the

Pit Initiation in CO2 Corrosion of Iron and Steel,” CORRO-SION/2000, paper no. 1 (Houston, TX: NACE, 2000).

17. G. Schmitt, D. Engels, “SEM/EDX Analysis of Corrosion Prod-ucts for Investigations on Metallurgy and Solution Effects inCO2 Corrosion,” CORROSION/98, paper no. 149 (Houston,TX: NACE, 1988).

18. J.L. Crolet, “Which CO2 Corrosion, Hence Which Prediction?,”in Predicting CO2 Corrosion in the Oil and Gas Industry,European Federation of Corrosion Publication no. 13 (London,U.K.: Institute of Materials, 1994), p 1.

19. J.L. Crolet, N. Thevenot, A. Dugstad, “Role of Free Acetic Acidon the CO2 Corrosion of Steels,” CORROSION/99, paper no.24 (Houston, TX: NACE, 1999).

20. S. Nesic, J.L. Crolet, D.M. Drazic, “Electrochemical Propertiesof Iron Dissolution in the Presence of CO2—Basic Revisited,”CORROSION/96, paper no. 3 (Houston, TX: NACE, 1996).

21. B.F.M. Pots, “Mechanistic Models for the Prediction of CO2

Corrosion Rates under Multi-Phase Flow Conditions,” COR-ROSION/95, paper no. 137 (Houston, TX: NACE, 1995).

22. S. Nesic, R. Nyborg, A. Stangeland, “Mechanistic Modelingfor CO2 Corrosion with Protective Iron Carbonate Films,”CORROSION/2001, paper no. 40 (Houston, TX: NACE,2001).

23. K. Videm, A. Dugstad, “Galvanic Influence of CO2 Corrosion,”CORROSION/89, paper no. 468 (Houston, TX: NACE, 1989).

24. K. Videm, A.M. Koren, Corrosion 49, 9 (1993): p. 746-754.25. J.L. Crolet, N. Thevenot, S. Nesic, “Role of Conductive Corro-

sion Products on the Protectiveness of Corrosion Layers,”CORROSION/96, paper no. 4 (Houston, TX: NACE, 1996).

26. A. Ikeda, S. Mukai, M. Ueda, “Prevention of CO2 Corrosion ofLine Pipe and Oil Country Tubular Goods,” CORROSION/84,paper no. 289 (Houston, TX: NACE, 1984).

27. J.L. Crolet, “Corrosion in Oil and Gas Production,” in Corro-sion and Anticorrosion, eds. G. Beranger, H. Mazille (Paris,France: Hermes Science, 2002).



28. K. Videm, A. Dugstad, “Effect of Flow Rate, pH, Fe2+ Concen-tration, and Steel Quality on the CO2 Corrosion of CarbonSteels,” CORROSION/87, paper no. 42 (Houston, TX: NACE,1987).

29. K. Videm, A. Dugstad, Mater. Perform. 3 (1989): p. 63-67.30. K. Videm, A. Dugstad, L. Lunde, “Influence of Alloying Elements

upon the CO2 Corrosion Rate of Low-Alloyed Carbon Steels,”CORROSION/91, paper no. 473 (Houston, TX: NACE, 1991).

31. A. Dugstad, “The Importance of FeCO3 Supersaturation on theCO2 Corrosion of Carbon Steels,” CORROSION/92, paper no.14 (Houston, TX: NACE, 1992).

32. M. Ueda, A. Ikeda, “Effect of Microstructure and Cr Content inSteel on CO2 Corrosion,” CORROSION/96, paper no. 13(Houston, TX: NACE, 1996).

33. R. Nyborg, A. Dugstad, P. Dronen, “Effect of Chromium onMesa Corrosion Attack of Carbon Steel,” Eurocorr 1997,Conf. of European Federation of Corrosion, held Sept. 22-25(London, U.K.: Institute of Materials, 1997).

34. B. Mishra, S. Al-Hassan, D.L. Olson, M.M. Salama, Corrosion53, 11 (1997): p. 852-859.

35. K. Videm, A. Dugstad, Mater. Perform. 4 (1989): p. 46-50.36. J.L. Crolet, M.R. Bonis, SPE Prod. Eng. 11 (1991): p. 449-453.37. B. Mishra, D.L. Olson, S. Al-Hassan, M.M. Salama, “Physical

Characteristics of Iron Carbonate Scale Formation in Line PipeSteels,” CORROSION/92, paper no. 13 (Houston, TX: NACE,1992).

38. K. Videm, J. Kvarekvaal, T. Perez, G. Fitzsimons, “SurfaceEffects on the Electrochemistry of Iron and Carbon Steel Elec-trodes in Aqueous CO2 Solutions,” CORROSION/98, paper no.1 (Houston, TX: NACE, 1998).

39. B. Kaasa, T. Ostvold, “Prediction of pH and Mineral Scaling inWaters with Varying Ionic Strength Containing CO2 and H2Sfor 0<T(°C)<200 and 1<P(bar)<500,” CORROSION/98, paperno. 62 (Houston, TX: NACE, 1998).

40. J.L. Crolet, M. Pourbaix, A. Pourbaix, “The Role of TraceAmount of Oxygen on the Corrosivity of H2S Media,” CORRO-SION/91, paper no. 22 (Houston, TX: NACE, 1991).

41. A. Dugstad, “Formation of Protective Corrosion Films duringCO2 Corrosion of Carbon Steel,” Eurocorr 1997, Conf. of Euro-pean Federation of Corrosion, held Sept. 22-25 (London, U.K.:Institute of Materials, 1997).

42. S. Al Hassan, B. Mishra, D.L. Olson, M.M. Salama, Corrosion54, 6 (1998).

43. E. Gulbrandsen, R. Nyborg, “Effect of Steel Microstructure andComposition on Inhibition of CO2 Corrosion,” CORROSION/2000, paper no. 23 (Houston, TX: NACE, 2000).

44. M.B. Kermani, J.C. Gonzales, C. Linne, M. Dougan, R.Cochrane, “Development of Low-Carbon Cr-Mo Steels withExceptional Corrosion Resistance for Oilfield Applications,”CORROSION/2001, paper no. 01065 (Houston, TX: NACE,2001).

45. R.M. Grau, “Mechanisms for Improved Corrosion Resistance ofSteels in Carbonic Acid Environments” (PhD thesis, Universityof Leeds, 2000).

46. M.L. Johnson, M.B. Tomson, “Ferrous Carbonate PrecipitationKinetics and its Impact on CO2 Corrosion,” CORROSION/91,paper no. 268 (Houston, TX: NACE, 1991).

47. K. Videm, A. Dugstad, L. Lunde, “Parametric Study of CO2

Corrosion of Carbon Steel,” CORROSION/94, paper no. 14(Houston, TX: NACE, 1994).

48. J.L. Crolet, M.R. Bonis, MP 24, 5 (1984): p. 35-42.49. S. Nesic, J. Postlethwaite, “Modeling of CO2 Corrosion Mecha-

nisms,” in Advanced Research Workshop on Modeling AqueousCorrosion: From Individual Pits to System Management, Proc.of the NATO Advanced Research Workshop, eds. K.R.Threthewey, P.R. Roberge, held Sept. 6-8 (Kluwer AcademicPublishers, 1994).

50. J.R. Shadley, S.A. Shirazi, E. Dayalan, E.F. Rybicki, F.D. deMoraes, “CO2 Corrosion Prediction in Pipe Flow under FeCO3

Scale Forming Conditions,” CORROSION/98, paper no. 51(Houston, TX: NACE, 1998).

51. K. Videm, J. Kvarekvaal, Corrosion 51, 4 (1995): p. 260-269.52. A. Ikeda, M. Ueda, S. Mukai, “Influence of Environmental Fac-

tors on Corrosion, Advances in CO2 Corrosion,” vol. 2, Proc.CORROSION/84 and CORROSION/85 Symp. on CO2 Corro-sion in the Oil and Gas Industry (Houston, TX: NACE, 1985).

53. Y. Garsany, D. Pletcher, B. Hedges,”The Role of Acetate in CO2

Corrosion of Carbon Steel: Has the Chemistry Been Forgot-ten?,” CORROSION/2002, paper no. 02273 (Houston, TX:NACE, 2002).

54. J.D. Garber, K.A. Sangita, “Factors Affecting Iron CarbonateScale in Gas Condensate Wells Containing CO2,” CORRO-SION/98, paper no. 19 (Houston, TX: NACE, 1998).

55. J.L. Crolet, M.R. Bonis, “The Role of Acetate Ions in CO2 Cor-rosion,” CORROSION/83, paper no. 160 (Houston, TX: NACE,1983).

56. J.L. Crolet, S. Olsen, W. Wilhelmsen, “Influence of a Layer ofIndissolved Cementite on the Rate of the CO2 Corrosion ofCarbon Steel,” CORROSION/94, paper no. 4 (Houston, TX:NACE, 1994).

57. B.F.M. Pots, E.L.J.A. Hendriksen, “CO2 Corrosion under Scal-ing Conditions—The Special Case of Top-of-the-Line Corro-sion in Wet Gas Pipelines,” CORROSION/2000, paper no. 31(Houston, TX: NACE, 2000).

58. J.L. Crolet, consultant, correspondence to M.B. Kermani (Au-gust through November 2002).

59. U. Lotz, L. van Bodengom, C. Ouwehand, “Effect of Oil or GasCondensate on Carbonic Acid Corrosion,” CORROSION/90,paper no. 41 (Houston, TX: NACE, 1990).

60. A.S. Green, B.V. Johnson, H.J. Choi, “Flow-Related Corrosionin Large Diameter Multiphase Flowlines,” 65th SPE AnnualTechnical Conf. and Exhibition of the Society of PetroleumEngineers, paper no. SPE 20685 (Richardson, TX: Society ofPetroleum Engineers [SPE], 1990).

61. K.D. Efird, R.J. Jasinski, Corrosion 45, 2 (1989): p. 165-171.62. U. Lotz, L. Van Bodegom, C. Ouwehand, Corrosion 47, 8

(1991): p. 635-645.63. H.J. Choi, T. Tonsuwannarat, “Unique Roles of Hydrocarbons

in Flow-Induced Sweet Corrosion of X-52 Carbon Steel in WetGas Condensate Producing Wells,” CORROSION/2002, paperno. 02559 (Houston, TX: NACE, 2002).

64. M. Castillo, H. Rincon, S. Duplat, J. Vera, E. Baron, “Protec-tive Properties of Crude Oils in CO2 and H2S Corrosion,” COR-ROSION/2000, paper no. 5 (Houston, TX: NACE, 2000).

65. C. de Waard, L. Smith, B. Craig, “Influence of Crude Oil onWell Tubing Corrosion Rates,” Eurocorr 2001, Conf. of Euro-pean Federation of Corrosion (London, U.K.: Institute of Mate-rials, 2001).

66. J. Smart, “Wetability—A Major Factor in Oil and Gas SystemCorrosion,” CORROSION/93, paper no. 70 (Houston, TX:NACE, 1993).

67. B. Hedges, D. Paisley, R. Woollam, “The Corrosion InhibitorAvailability Model,” CORROSION/2000, paper no. 34 (Hous-ton, TX: NACE, 2000).

68. American Petroleum Institute, Recommended Practice 14E(API RP 14E), “Recommended Practice for Design and Installa-tion of Offshore Production Platform Piping Systems” (Wash-ington DC: API, 1981).

69. A. Dugstad, L. Lunde, K. Videm, “Influence of Alloying Ele-ments upon the CO2 Corrosion Rate of Low-Alloyed CarbonSteels,” CORROSION/91, paper no. 473 (Houston, TX: NACE,1991).

70. E.W.J van Hunnik, B.F.M Pots, E.L.J.A. Hendriksen, “TheFormation of Protective FeCO3 Corrosion Product Layers inCO2 Corrosion,” CORROSION/96, paper no. 6 (Houston, TX:NACE, 1996).

71. T. Rogne, T.G. Eggen, U. Steinsmo, “Corrosion of C-Mn-Steeland 0.5% Cr Steel in Flowing CO2-Saturated Brines,” CORRO-SION/96, paper no. 33 (Houston, TX: NACE, 1996).

72. A. Dugstad, “Mechanism of Protective Film Formation duringCO2 Corrosion of Carbon Steel,” CORROSION/98, paper no.31 (Houston, TX: NACE, 1998).

73. N. Blackburn, “Downhole Materials Selection for Clyde Pro-duction Wells: Theory and Practice,” Society of Petroleum En-gineers, European Production Operations Conf. andExhibition, paper no. SPE 27604, held March 15-17(Richardson, TX: SPE, 1993).

74. A.J. McMahon, Mater. Perform. 36, 12 (1997): p. 50-53.75. P.I. Nice, H. Takabe, M. Ueda, “The Development and Imple-

mentation of a New Alloyed Steel for Oil and Gas ProductionWells,” CORROSION/2000, paper no. 154 (Houston, TX:NACE, 2000).

76. P.I. Nice, M. Ueda, “The Effect of Microstructure and Chro-mium Alloying Content to the Corrosion Resistance of Low-Alloy Steel Well Tubing in Seawater Injection Service,”CORROSION/98, paper no. 3 (Houston, TX: NACE, 1998).

77. A. Dugstad, H. Hemmer, M. Seiersten, “Effect of Steel Micro-structure upon Corrosion Rate and Protective Iron CarbonateFilm Formation,” CORROSION/2000, paper no. 23 (Houston,TX: NACE, 2000).

usuario

Resaltado



78. R. Cochrane, Leeds University, work in progress.79. D.E. Cross, “Mesa-Type CO

2 Corrosion and its Control,”

CORROSION/93, paper no. 118 (Houston, TX: NACE, 1993).80. M.B. Kermani, J.C. Gonzales, G.L. Turconi, D. Edmonds,

G. Dicken, L. Scoppio, “Development of Superior CorrosionResistance 3%Cr Steels for Downhole Applications,” CORRO-SION/2003, paper no. 03116 (Houston, TX: NACE, 2003).

81. Petroleum and Natural Gas Industries—Materials for Use inH2S-Containing Environments in Oil and Gas Production—Part 1, ISO 15156 (Geneva, Switzerland, International Organi-zation for Standardization [ISO], 2002).

82. J.L. Crolet, S. Olsen, W. Wilhelmsen, “Observation of MultipleSteady States in the CO2 Corrosion of Carbon Steel,” CORRO-SION/95, paper no. 188 (Houston, TX: NACE, 1995).

83. K. Videm, A. Dugstad, “Film-Covered Corrosion, Film Break-down, and Pitting Attack of Carbon Steels in Aqueous CO2

Environments,” CORROSION/90, paper no. 186 (Houston,TX: NACE, 1990).

84. S.H. Drissi, J.P. Mike, J.M. Genin, Corros. Sci. (1996): p. 623.85. C.A. Palacios, J.R. Shadley, Corrosion 47, 2 (1991).86. J.K. Heuer, J.F. Stubbins, Corrosion 54, 7 (1998): p. 566-577.87. S. Rajappa, R. Zhang, M. Gopal, “Modeling the Diffusion Ef-

fects through the Iron Carbonate Layer in the Carbon DioxideCorrosion of Carbon Steel,” CORROSION/98, paper no. 16(Houston, TX: NACE, 1998).

88. Y.J.T. Kinsella, S. Bailey, Corrosion 54, 10 (1998): p. 835-842.89. J.R. Shadley, S.A. Shirazi, E. Dayalan, E.F. Rybicki, G. Vani,

“Modeling CO2 Corrosion of Carbon Steels in Pipe Flow,”CORROSION/95, paper no. 118 (Houston, TX: NACE, 1995).

90. D.W. Shannon, “Role of Chemical Components in GeothermalBrine on Corrosion,” CORROSION/78, paper no. 57 (Houston,TX: NACE, 1978).

91. C. de Waard, U. Lotz, A. Dugstad, “Influence of Liquid FlowVelocity on CO2 Corrosion: A Semi-Empirical Model,” CORRO-SION/1995, paper no. 128 (Houston, TX: NACE, 1995).

92. F.D. de Moraes, J.R. Shadley, J. Chen, E.F. Rybicki, “Charac-terization of CO2 Corrosion Product Scales Related to Environ-mental Conditions,” CORROSION/2000, paper no. 30(Houston, TX: NACE, 2000).

93. Metals Handbook, “Corrosion,” 9th ed., vol. 13 (MaterialsPark, OH: ASM International, 1987), p. 1,233.

94. E.C. Greco, W.B. Wright, Corrosion 18 (1962): p. 119t.95. P.R. Rhodes, Electrochemical Society Extended Abstracts,

vol. 76, no. 2 (Pennington, NJ: Electrochemical Society,1976), p. 300.

96. J.L. Crolet, “Protectiveness of Corrosion Layers,” in ModelingAqueous Corrosion: From Individual Pits to System Manage-

ment, eds. K.R. Trethewey, P.R. Roberge, NATO ASI Series,Series E: Applied Sciences, vol. 266 (Dordrecht NL, KluwerAcademic Publishers, 1994), p. 1-28.

97. R. Nyborg, A. Dugstad, “Mesa Corrosion Attack in CarbonSteel and 0.5% Chromium Steel,” CORROSION/1998, paperno. 29 (Houston, TX: NACE, 1998).

98. J.R. Shadley, S.A. Shirazi, E. Dalayan, M. Ismail, E.F.Rybicki, Corrosion 52, 9 (1996).

99. A. Morshed, “Surface Modification for Corrosion Protection ofSteel Pipes” (PhD thesis, University College London, 2002).

100. R. Nyborg, “Overview of CO2 Corrosion Models for Wells andPipelines,” CORROSION/2002, paper no. 02233 (Houston,TX: NACE, 2002).

101. C. de Waard, U. Lotz, D.E. Milliams, Corrosion 47, 12 (1991):p. 976-985.

102. C.S. Fang, J.D. Garber, R. Perkins, J.R. Reinhardt, “Com-puter Model of a Gas Condensate Well Containing CarbonDioxide,” CORROSION/89, paper no. 465 (Houston, TX:NACE, 1989).

103. Y.M. Gunalton, “Combining Research and Field Data for Cor-rosion Rate Prediction,” CORROSION/94, paper no. 14 (Hous-ton, TX: NACE, 1994).

104. G. Liu, R.C. Erbar, “Detailed Simulation of Gas Well DownholeCorrosion in Carbon Steel Tubulars,” CORROSION/90, paperno. 30 (Houston, TX: NACE, 1990).

105. M.R. Bonis, J.L. Crolet, “Basics of the Prediction of the Risksof CO2 Corrosion in Oil and Gas,” CORROSION/89, paper no.466 (Houston, TX: NACE, 1989).

106. Condensate Well Corrosion, NGAA, Tulsa, OK, 1953.107. NACE MR0175, “Sulfide Stress Cracking Resistant Metallic

Materials for Oilfield Equipment” (Houston, TX: NACE, 2001).108. Guidelines on Materials Requirements for Carbon and Low-

Alloy Steels for H2S-Containing Environments in Oil and GasProduction, Publication no. 16 (London, U.K.: The Institute ofMaterials, European Federation of Corrosion, 1995).

109. K. Mudge, C.J. Levesque, Oil Gas J. 27 (1982): p. 245.110. J.B. Bradburn, “Water Production: An Index to Corrosion,”

NACE South Central Region Conf. (Houston, TX: NACE,1977).

111. J. Kolt, E. Buck, D.D. Erickson, M. Achour, “Corrosion Pre-diction and Design Considerations for Internal Corrosion inContinuously Inhibited Wet Gas Pipelines,” U.K. CorrosionConf. 1990, vol. 3 (London, U.K.: Institute of Materials, 1990),p. 217.

112. C. de Waard, U. Lotz, “Prediction of CO2 Corrosion of CarbonSteel,” CORROSION/93, paper no. 69 (Houston, TX: NACE,1993).

An updated, free guide for the prospectiveCORROSION author, with tips on manuscript

preparation, format, style, color artwork, andeditorial policies.

CORROSIONTHE JOURNAL OF SCIENCE AND ENGINEERING

To order, contact: NACE Membership Services Department, 1440 South Creek Drive,Houston, TX 77084-4906; Phone: 281/228-6223 or Fax: 281/228-6329; ask for Item no. 32143. Forimmediate delivery by fax, call 1-800-327-3134. This information is also available on the NACE Webpage at www.nace.org.

CORROSION

Author'sGuide*

*New Guidelines Effective Jan. 1, 2000.Item # 32143

ContentsGeneral ................................... 1

Submission of Manuscripts ...... 1

Acceptance Criteria ................. 1

Acceptable Forms of Articles .... 2

Manuscript Format ................. 2

Publication Procedures ............ 2

General Style Requirementsfor All NACE Publications ........ 3

Abbreviations, Acronyms,and Symbols ........................... 3

Equations and Footnotes...... 4-5

Graphics ................................. 5

Metric Measurements .............. 6

Numbers and Punctuation ... 6-7

References ............................... 7

Trade Namesand Author Affiliations ............ 9

Index ..................................... 12

Author Checklist .................... 14

CORROSION SCIENCE

CORROSIONTHE JOURNAL OF SCIENCE AND ENGINEERING

Vol. 56, No. 1 January 2000

Founded 1945

3

1224

32

41

48

CORROSION ENGINEERING

Effect of Biomineralized Manganese on the Corrosion Behavior of C1008Mild SteelB.H. Olesen, P.H. Nielsen, and Z. Lewandowski

An Electrochemical Approach to Predicting Long-Term Localized Corrosionof Corrosion-Resistant High-Level Waste Container MaterialsD.S. Dunn, G.A. Cragnolino, and N. Sridhar

90

80

57

70

Path Dependence of the Potential-Current Density State for CathodicallyPolarized Steel in SeawaterW.H. Hartt and S. Chen

Influence of Overaging Treatment on Localized Corrosion of Al 6056V. Guillaumin and G. Mankowski

Anticorrosion, Antiscale Coatings Obtained on the Surface of Titanium Alloysby Microarc Oxidation Method and Used in SeawaterS.V. Gnedenkov, P.S. Gordienko, S.L. Sinebrukhov, O.A. Khrisanphova, and T.M. Skorobogatova

Prediction of Stress Corrosion Cracking Susceptibility of Stainless SteelsBased on Repassivation KineticsH.S. Kwon, E.A. Cho, and K.A. Yeom

In-Situ Imaging of Chloride Ions at the Metal/Solution Interface by ScanningCombination MicroelectrodesC.-J. Lin, R.-G. Du, and T. Nguyen

Galvanostatic Pulse Measurements of Passive and Active Reinforcing Steelin ConcreteD.W. Law, S.G. Millard, and J.H. Bungey

Variation of Slow Strain Rate Test Fracture Mode of Type 304L Stainless Steelin 288°C WaterN. Saito, Y. Tsuchiya, F. Kano, and N. Tanaka

Corrosion Behavior of High-Purity Fe-Cr-Ni Alloys in the Transpassive ConditionM. Mayuzumi, J. Ohta, and K. Kako

9.CORROS

Documents

Transcript of 9.CORROS