MMAATTEERRIIAALLSS DDEESSIIGGNN SSTTRRAATTEEGGYY::

EEFFFFEECCTTSS OOFF HH22SS//CCOO22 CCOORRRROOSSIIOONN OONN MMAATTEERRIIAALLSS SSEELLEECCTTIIOONN

Bijan Kermani, KeyTech, Camberley, UK

John Martin, BP Exploration, Sunbury on Thames, UK

Khlefa Esaklul, BP Kuwait, Kuwait

AABBSSTTRRAACCTT

Corrosion remains a key obstacle to sustaining operational success in hydrocarbonproduction. Its continued occurrence affects the economy and has consequences for the safety of people and integrity of facilities. A central element in the design of facilities and corrosion mitigation is the correct choice and deployment of materials which are both economical andsuitable to provide satisfactory performance over the design life. This paper captures the current understanding of corrosion mechanisms in the combined presence of H2S and CO2 acidic gases anddiscusses a systematic approach to materials design strategy for hydrocarbon production systems. The paper does not deal with the important environmental cracking aspects associated with sour service, but rather concentrates purely on metal loss degradation process. The combination of H2Sand CO2 modifies the corrosion characteristics significantly as compared to damage caused in the sole presence of CO2 or H2S. An H2S/CO2 ratio is introduced to indicate the trends governingcorrosion mechanism, i.e. dominated by CO2, H2S or a mixed mode of damage. A simple guideline has been produced offering a rule of thumb in addressing respective corrosion damages.

KKeeyywwoorrddss:: CCaarrbboonn aanndd LLooww AAllllooyy SStteeeellss,, CCoorrrroossiioonn,, IInntteeggrriittyy MMaannaaggeemmeenntt,, MMaatteerriiaallss SSeelleeccttiioonnSSttrraatteeggyy,, PPrroodduuccttiioonn,, SSoouurr SSeerrvviiccee,, SSwweeeett CCoorrrroossiioonn..

IINNTTRROODDUUCCTTIIOONN

Corrosion in hydrocarbon systems manifests itself in several forms amongst which CO2

corrosion (sweet corrosion), H2S corrosion (sour corrosion) in the production systems and oxygen corrosion in water injection systems are by far the most prevalent forms of attack [1]. The environmental sensitive cracking damage caused by H2S and consequent materials optimisation areother very important aspects in these systems, but these are already covered in detail elsewhere[2, 3]. Corrosion in water injection systems is also outside the scope of the present overview. An

1

additional key element affecting corrosion is the presence of elemental sulfur in the productionstream, which is again beyond the scope of the present paper.

The majority of oilfield failures result from CO2 corrosion of carbon and low alloy steels (CLASs), primarily due to inadequate knowledge/predictive capability and the poor resistance of carbonsteels to this type of attack [1]. Its understanding, prediction and control are key challenges tosound facilities design, operation and subsequent integrity assurance. Extensive research over thepast five decades has focused on the mechanistic and engineering understanding of CO2 corrosionof CLASs, with a view to develop a realistic model to predict its occurrence. These are broadly covered in a review elsewhere [1]. Despite this, the majority of existing quantitative modelsremain unreliable in predicting the actual long-term CO2 corrosion rate of CLASs [1]. Theanomalies are attributed to "field artefacts" with no clear indication of the cause. One key cause ofthe difference is now attributed to the effects of organic acid [4,5] a chemical normally ignored bymany. An added complication is the presence of H2S which in turn affects potential corrosivity, in-situ pH and interferes with the formation of corrosion product.

This review article captures the current understanding and means of dealing with H2S in CO2

corrosion evaluations for CLASs in hydrocarbon production. It provides information on themechanisms, highlights key parameters affecting the complementary influence of the two acid gases and draws attention to areas requiring further research. The primary focus has been placedon two key parameters affecting CO2 corrosion in the presence of H2S including (i) the nature of the surface film and (ii) development of an engineering guide for dealing with the risk of H2S-CO2

corrosion in production conditions. A brief overview of the specific material choice route fordifferent production areas is provided within the context of a materials design strategy. The reviewhas highlighted key areas of progress and has drawn attention to the future direction of researchand development to enable improved and economical design of facilities for oil and a gasproduction.

Background

Both CO2 and H2S are acid gases that when produced with the hydrocarbon phase canrender the associated water (condensed or formation) corrosive and lead to severe degradation. Corrosion resulting from each of these two acidic gases has its unique characteristics and, as aresult, has received considerable industry attention, both to understand the corrosion mechanismsassociated with the particular acid gas and the options available to mitigate the resulting corrosion[1-9]. Each of these gases occurs naturally in some of the producing reservoirs or may result fromexternal contamination of the reservoir, such as the case of reservoir souring that may result whenseawater is injected for secondary recovery or the use of gas injection for reservoir pressuremaintenance. Selection of materials to combat corrosion relies mainly on the type of corrosionanticipated (e.g. whether general or localised [pitting]), the confidence in predicting the rate and type of corrosion, risk of failure and life cycle cost. While the primary concern in selection ofmaterials in H2S containing systems is the sulfide stress cracking (SSC), the issue of corrosionshould not be underestimated. SSC and other forms of cracking in H2S containing environmentsare well understood [2,3] and are not covered in this review. The focus of this paper is on thewastage corrosion in the combined presence of H2S and CO2.

Relative Corrosiveness of CO2 and H2S and O2

While the respective corrosion mechanisms of the two acid gases prevailing in hydrocarbon systems, plus oxygen that can occur as a contaminant, are vastly different, a simple comparisonunder specific conditions was presented by Jones [10]. This is shown in Figure 1. The data arebased on corrosion rates measured and computed by exposing clean carbon steel samples to water solutions containing various concentrations of each gas at 25oC. It has been claimed that theserates compare favourably with field data [10]. It is important to note that the synergistic effects ofthese gases are extremely influential in materials design and a point of consideration. A simple addition of respective damage rates does not necessarily lead to the overall damage as the complementary process is very complex. Furthermore, such a simple correlation does not bear in mind localised type of attack wherein the damage rate can be significantly higher than the overall

2

rate. However, the information provides a general idea of comparative corrosiveness of the threeimportant gases at low temperature.

TTYYPPEESS OOFF CCOORRRROOSSIIOONN DDAAMMAAGGEE

This section refers to the types of damage encountered in hydrocarbon production systemsin CO2 only, H2S only and mixed CO2-H2S containing conditions.

CCOO22 CCoonnttaaiinniinngg SSttrreeaammss

CO2 is usually present in produced fluids and although it does not generally by itself causethe catastrophic failure mode of cracking associated with H2S [2,3] its presence in contact with anaqueous phase can nevertheless result in very high corrosion rates, especially where the mode ofattack is localised (e.g. mesa corrosion) [1].

CO2 Corrosion occurs primarily in the form of general corrosion and three variants of localisedcorrosion, i.e. pitting, mesa attack and flow-induced localised corrosion [1,11]:

Pitting corrosion normally occurs under relatively stagnant conditions (around the dew pointfor gas systems) – there are no certain rules to predict when such attack will occur.

Mesa attack is a form of localised corrosion occurring under low to medium flow conditions(resulting from the localized removal of the protective carbonate film) – attack showing alarge flat attack bottom steps with sharp edges– excessive rates at these areas occurs aroundtemperature where carbonate can form but not stable

Flow induced localised corrosion occurring at high flow conditions - corrosion takes the formof pits at sites of highly turbulent flow (often considered a form of erosion-corrosion)

CO2 corrosion is influenced by a number of parameters including environmental, physical andmetallurgical variables [1]. The majority of these have been extensively covered by a number of authors and captured elsewhere [1,11]. Notable parameters affecting CO2 corrosion include:

Fluid make-up as affected by water chemistry, organic acids, pH, water wetting, hydrocarboncharacteristics and phase ratios

CO2 and H2S content (and possible oxygen contaminants)

Temperature

Steel surface including corrosion film morphology, presence of wax and ashphaltene

Fluid dynamics

Steel chemistry

All parameters are interdependent and can interact in many ways to influence CO2 corrosion asdescribed elsewhere [1].

HH22SS CCoonnttaaiinniinngg SSttrreeaammss;; TThhee MMeecchhaanniissmm

H2S results in a weak acid when dissolved in water. It affects CLASs in a similar manner tothat of CO2 with all influential parameters outlined earlier for CO2 corrosion affecting its processand mechanism. The type of damage caused by H2S appears in the form of localised corrosion or general corrosion, depending upon the type and nature of corrosion product formed. H2S corrosionhas been claimed to be strongly dependent on chloride ion concentration with severe damage ratein some situations, although the presence of other corrosive agents and fluid chemistry on this rate of degradation is unknown [12-15]. The corrosion reaction often leads to the formation of ironsulfide (FeS) scales, which under certain conditions are highly protective. However, theirbreakdown (i.e. under turbulent flow conditions) can lead to very severe localised corrosion in asimilar manner to that for FeCO3 breakdown in the case of CO2 corrosion [1]. The kinetics andnature of FeS film formation, stability and its contribution to reducing corrosion are key to affordingprotection. Also, like CO2 corrosion, the corrosion rate is affected by fluid chemistry, organic acidsand flow velocity in addition to the presence of elemental sulfur [13].

3

The ability of H2S to affect acidity is indicated by its ionisation as follows [11]: H2S H+ + HS- (1)

As the H+ is removed through cathodic reaction of hydrogen reduction, more is formed and hydrogen gas readily appears on steels exposed to oxygen free water containing H2S as follows: 2H+ + 2e 2H (atomic hydrogen) H2 (molecular hydrogen) (2)

The anion (HS-) dissociates further to S2- and H+. The S2- ion reacts with iron to form the black FeS corrosion product commonly found in service. H2 may not be present in the bulk solution, but itforms locally within the corrosion layer as a cathodic corrosion product diffusing from itselectrochemical production at the metal surface to its final dispersion in the bulk at the outersurface [16].

MMiixxeedd HH22SS//CCOO22 CCoonnttaaiinniinngg SSttrreeaammss

Ignoring the environmental sensitive cracking aspects of corrosion problems associated withsour service, low levels of hydrogen sulfide can affect CO2 corrosion in different ways. H2S caneither increase CO2 corrosion by acting as a promoter of anodic dissolution through sulfideadsorption and affecting the pH or decrease sweet corrosion through the formation of a protectivesulfide scale. The exact interaction of H2S on the anodic dissolution reactions in the presence of CO2 is not fully understood [1].

For similar conditions, oil and gas installations could experience lower corrosion rates in sourconditions compared to completely sweet systems. This is due to the fact that the acid created bythe dissolution of hydrogen sulfide is about 3 times weaker than that of carbonic acids, but H2S gas is about 3 times more soluble in hydrocarbon phase than CO2 gas. As a result the effect of both CO2 and H2S gases on lowering the solution pH and potentially increasing corrosion rate are fundamentally the same. In addition, hydrogen sulfide may play a significant role on the type andproperties of the corrosion films, improving or undermining them [1,11].

Many papers have been published on the interaction of H2S with CLASs. However, literature dataon the interaction of H2S and CO2 is still limited since the nature of the interaction is highlycomplex. The majority of open literature indicates that CO2 corrosion rate is reduced in the presence of H2S at ambient temperatures. Nevertheless, it must be emphasised that H2S may also form a non-protective layer and that it may catalyse the anodic dissolution of bare steel [45].Steels may experience some form of rapid, localised corrosion in the presence of H2S, althoughvery little information is available. Published laboratory work has proved inconclusive, indicatingthat there is a need to carry out further studies in order to clarify the mechanism. In spite of the work on H2S corrosion of steels, no equations or models are available to predict corrosion, as is the case for CO2 corrosion of steels [1,11].

As a general rule in CO2 containing environments the presence of H2S can [1,16,45]:

Increase the corrosion risk by either:

o facilitating localised corrosion, at a rate greater than the general metal loss or localisedrate expected from CO2 corrosion, or

o preferentially forming an FeS corrosion product that is less protective than an ironcarbonate corrosion product

Decrease the corrosion risk by promoting the formation of an FeS corrosion product filmthrough either

o replacing a less protective iron carbonate film, or

o forming a combined protective layer of iron sulphide and iron carbonate

In the presence of both acid gases the corrosion process is governed by the dominant acid gas. The presence of H2S in CO2 containing producing environments has been reviewed by Pots et al [14]. They have introduced a notion of CO2/H2S ratio and considered three different corrosiondomains based on the dominance of corrosion mechanism as affected by the dominating acid gas.These are tabulated in Table 1 and shown in Figure 2 [14] as follows:

4

CO2/H2S < 20

o Corrosion dominated by H2S

FeS as the main corrosion product

20 < CO2/H2S < 500

o Mixed CO2/H2S corrosion dominance

A mixture of FeS and FeCO3 as the main corrosion products

CO2/H2S > 500

o CO2 corrosion dominates

FeCO3 as the main corrosion product.

These limits will be subject to environmental conditions highlighted in CO2 containing streams and described in a later section.

This is in support of other investigations [17,18] in which it has been concluded that the CO2/H2Sratio determines the nature of scale and in turn the corrosion mechanism. Dunlop [17] proposedthat as a general rule for CO2/H2S > 500, corrosion is dominated by CO2 and FeCO3 will form.When the ratio is < 20, FeS scale will form and H2S corrosion dominates as outlines in Figure 2[14].

Smith [19] identified that the corrosion rate limiting step is determined by the type of corrosionproduct that forms as a result of the chemical reactions of CO2 and H2S. He goes on and describesthe protectiveness or lack of it based on the thermodynamic stability of different compounds.Smith also developed a relationship that determines the boundaries of the FeCO3 and mackinawitescales by extending the Dunlop correlation and proposed the equilibrium boundary betweenmackinawite and FeCO3.

It is difficult to extrapolate laboratory based data generated over a short period to real lifecorrosion reactions and describe kinetically driven corrosion processes in terms of thermodynamicdata. It is worth noting that protective layers are always thin as they progressively reduce ionictransport and corrosion reaction, whereas non-protective layers are normally thick or even profuse[4,45]. Therefore, regarding a threshold in term of corrosion rate, the simple corrosion productlayer thickness could be an indicator of the nature of sulfide formed, apart from thermodynamic data in potential-pH diagrams. The explanation for the disparity in protectiveness of corrosionproduct in CO2 and H2S containing media has been explained in terms of diffusion transportphenomena through the liquid phase within the corrosion product layer [16,45]. It is argued thatdepending on the dominant process, three possible types of corrosion control processes are plausible; soluble, insoluble cationic (IC) and insoluble anionic (IA) layers. He goes on to say thatin H2S-containing media through the formation of IA-type deposit can explain the presence of alayer of highly soluble corrosion products, including FeCl2, between an outer layer of virtuallyinsoluble FeS and a corroding steel substrate. It is said that this is also true for the very highcorrosion rates observed beneath thick profuse mackinawite deposits. Furthermore, a protective IC layer formed in the presence of excess H2S can explain the formation of pyrite, FeS2, while a non- protective IA layer, produced under a deficiency of H2S, can explain the formation of mackinawite,FeS1-e. Therefore, it is probably more correct to consider that it is the mechanism of protectivenesswhich determines the nature of the solid deposit, rather than the opposite [16,45].

The in-situ pH is also a key parameter governing corrosion in wet hydrocarbon production conditions affecting the formation and retainment of a protective layer. The in-situ pH is influencedby three controlling buffer systems [5]:

CO2/HCO3- through reaction (3)

H2S/HS- through reaction (1)

HAc/Ac - (or other organic acids or other organic) through reaction (4) CO2 + H2O HCO3

- + H + (3)

5

HAc Ac- + H+ (4)

The carbonic, sulfidic and acetic buffers are represented by the mass action laws of their respectivedissociation equilibrium as outlined in reactions 1, 3 and 4.

When several buffers are simultaneously present, they react together since H+ is a common speciesin their respective dissociation equilibriums (5) and (6):

HAc + HCO3- Ac- + CO2 + H2O (5)

H2S + HCO3- HS- + CO2 + H2O (6)

These and the corresponding in-situ pH in turn influence the corrosion process.

The synergistic interaction of these three buffering (and others) reactions govern corrosivity asinfluenced by the formation of protective scales and they should constitute the basis of any corrosion analysis in hydrocarbon production systems.

KKEEYY FFAACCTTOORRSS IINNFFLLUUEENNCCIINNGG HH22SS//CCOO22 CCOORRRROOSSIIOONN

The operational parameters affecting CO2-H2S corrosion include those outlined earlier for CO2

containing conditions, notably:

CO2/H2S ratio

Temperature

Fluid Chemistry (water chemistry, pH, organic acids, water cut, oil wetability, phase ratios,etc.)

The hydrocarbon phase

Flow characteristics and fluid velocity

Steel surface, including corrosion products, scales, wax and asphaltene

Steel chemistry

These parameters, highlighted in Figure 3, are interdependent and can interact in many ways toinfluence the corrosion process and the exact influence of many of these is still unknown. Inparticular the effect of hydrocarbon phase on corrosion behaviour still remains unanswered, not only in the case of CO2 corrosion, but also when both H2S and CO2 are present [1,10,11]. However, an overview of the current understanding of these parameters is captured in this section.As explained earlier, the interaction of the buffering reactions is a key consideration in thecorrosion process.

EEffffeecctt ooff CChhlloorriiddeess

Bich [12] reported very high corrosion rates in the order of 30 mm/y, in a failed gas pipelinewith high level of chlorides while other lines with low level of chlorides did not exhibit the highcorrosion rates. The high corrosion rate was attributed to the effect of chlorides on breaking down of the protective FeS scale and initiation of pitting corrosion. However, this may have been relatedto the influence of other constituents of the solution affecting the in-situ pH or organic acids, thepresence of which was not fully established.

Foroulis [20] reported large increase in corrosion rate with an increase in chloride content insolutions saturated with H2S and suggested that the increase is due to the increase in conductivityand the interference of the chloride ions with the formation of FeS protective film.

Agrawal et al [18] reported that there is strong correlation between the corrosion rate and theCO2/H2S ratio and the relation followed a bell-shape curve, with the peak corrosion rate occurringat an order of magnitude higher CO2/H2S ratio when the chlorides increased from 0.01 to 10% NaCl. This may suggest that chloride ions interfere with the formation of protective scales.Furthermore, they concluded that any damage in the protective film can lead to an acceleratedcorrosion unless and until the FeS protective film is reformed.

Hence, the role that chloride content of the environment plays is not fully established. However,its influence on corrosion of carbon and low alloy steels in CO2-H2S containing media is often

6

considered insignificant at low chloride contents. Nevertheless, chloride may have a role inaffecting the in-situ pH. Chloride also has some affinity to interfere with the formation ofprotective FeCO3 or pyrite and the tendency to influence its formation and growth on CLASs [4,16].The observations reported on the effect of chloride [12,20] may have been related to the influenceof other constituents of the media affecting the in-situ pH or organic acids the presence of which were not fully reported.

A critical chloride concentration of 10,000 ppm has been conservatively proposed [14] based on field experience and laboratory testing. It has been concluded that above a concentration of 10,000 ppm, the chloride ion can destroy the protective FeS scales and can lead to increasedcorrosion rate.

The role of chloride needs further clarification and a subject which should be taken in the context ofsolution chemistry and the nature of corrosion product.

EEffffeecctt ooff HH22SS CCoonncceennttrraattiioonn

Russ and Rainsford [21] reported that change in the CO2/H2S ratio from 3 mole % CO2/700ppm H2S to 3.75 mole % CO2/350 ppm H2S resulted in significant increase in corrosion of oilpipelines. In-line inspection revealed that the section of the line with CO2/H2S ratio of 43 had low or non detectable corrosion while the one that had a ratio of 88 showed localized area representing2.5% of the length of the line with pits 20-35% of the wall thickness. The difference in flow rate expressed as the shear stress was reported as 0.2 Pa for the segment with no corrosion and 1.0 Pain the segment that showed corrosion. These shear stresses were low so that corrosion could not be due to the increase in fluid velocity. Again the full fluid chemistry has not been reported.

Smith and de Waard [22] proposed an H2S reduction factor in their corrosion rate prediction model for CO2 corrosion. The factor is a function of the partial pressure ratio of H2S and CO2 as follows:

F H2S = 1 / (1 + 1800 (pH2S/pCO2)) (7)

They state that this factor is speculative since the protective FeS layer can suffer breakdown. In cases where FeS breakdown occurs the corrosion rate can be an order of magnitude higher thanthe corresponding rate for pure CO2. This high corrosion rate in the presence of H2S is a result ofdrop in the pH due to the reduction of the dissolved iron ions that occurs with FeS precipitation andgalvanic couple formed between the steel and corrosion scale.

Brown, Parakala and Nesic [23] studied the effect of low levels of H2S on CO2 corrosion and showed that in the absence of protective iron carbonate and iron sulfide scales very small amounts of H2S< 10 ppm in the gas phase can lead to rapid and significant reduction in the CO2 corrosion rate. The trend is arrested and somewhat reversed at higher H2S concentration. Protective adherent films formed at 60º C with 25 ppm H2S and 7.9 bar pressure at pH of 6.0.

EEffffeeccttss ooff LLooww HH22SS PPaarrttiiaall PPrreessssuurreess oonn CCOO22 CCoorrrroossiioonn RRaatteess

Recognising the importance of trace H2S on CO2 corrosion, a limited number of tests werecarried out using an ambient pressure corrosion loop facility [24]. The programme assessed the effects of low H2S partial pressures on CO2 corrosion. The partial pressures of H2S used were1.5x10-3, 1.5x10-2 and 1.5x10-1 psi (0.0001, 0.001 and 0.01 bar) corresponding to H2Sconcentrations of 100, 1,000 and 10,000 ppm (in the gas phase), respectively at an atmosphericpressure. Tests were carried out on linepipe steel grade X65 at 30, 50 and 75oC in the presence of 1 bar CO2 (14.5 psia) under two environmental conditions as shown in Table 1. Corrosion rates were determined by continuous LPR monitoring over a 24 hours’ period [24].

The results are summarised in Figures 4 and 5 for two conditions:

Chloride containing fluid with no buffering agent at a pH range of 3.8 to 4.0

Formation water with strong buffering agents at a pH range of pH Range 5.5 to 5.8

Also included are the predicted corrosion rates for these conditions, using the de Waard andMilliams model [25]. The respective values under sweet conditions are somewhat higher than those predicted by the model, particularly at lower temperatures.

7

Despite the inability to extrapolate the outcome of this limited study to develop a trend of corrosionrate versus H2S, it can be seen that low levels of H2S has a strong influence on CO2 corrosion bylowering the general rate of attack irrespective the environmental conditions. The lowering of damage rate increased progressively with increasing test temperature, although the magnitude of the reduction in corrosion rates was smaller in the buffered solution. The reduction in corrosionrates were considered to be due to the formation of a semi-protective FeS film or by stabilising aniron carbonate film.

It seems that the partial pressure range investigated was above that required for semi-protectivefilms to form but below that necessary to cause increased corrosion rates.

While the degree of damage by localised corrosion was examined, the results were not conclusive.Nevertheless, the rate of pit propagation was considered unlikely to exceed the predicted generalsurface corrosion rate predicted determined by CO2 corrosion rate prediction models.

The results indicate that at low levels of H2S which are defined as levels generally below the‘occurrence of SSC’ limits (i.e. Region 0 of ISO 15156/NACE MR0175 at <0.05 psi) can reduce corrosion by a factor of 3 to 4 [24].

EEffffeecctt ooff FFllooww aanndd TTeemmppeerraattuurreeBrown and Nesic [26] showed that mackinawite FeS scale is protective when the flow

conditions do not disturb the FeS scale but becomes less effective under turbulence flow conditions.Under conditions of porous film formation, the scale becomes less effective barrier and the corrosion rate increases. The key parameters in determining the film morphology are the FeCO3

and FeS supersaturation values. It has been claimed that the mechanisms of corrosion productfilm growth can produce multilayer films with some leading to increased corrosion rate andprobability of localised corrosion [26].

Omar et al. [27] showed that CO2-H2S corrosion is not dependent on temperature and flow velocityfor test conditions of 25 – 80ºC and 1 – 5 m/sec and the measured corrosion rates were lower than the predicted corrosion rates from pure CO2. At the highest velocity 5 m/sec they reported atendency toward localised corrosion attacks and development of pitting corrosion which they attributed to the local breakdown of the protective films due to the high shear stresses or flow eddies close to the film. The magnitude of shear stress at this flow velocity is near 77 Pa. Thisraises the issue of pitting corrosion under conditions where film breakdown may occur due to high flow rates. In addition, they reported that at 80º C multiple layers of corrosion product formedwith the inner layer close to the steel contained substantial fractions of iron oxides. The oxideswould typically form due to the limited sulfide ions indicating that the corrosion products act as diffusion barriers and slow the corrosion attack. The effect of iron oxide presence on the long termintegrity of the FeS protective layer is a major concern, although its presence may be related to laboratory test conditions as it is not a field produced corrosion product in CO2 environments.

EEffffeecctt ooff OOrrggaanniicc AAcciiddss

The significance role of organic acids on the performance of CLASs in CO2 containinghydrocarbon production systems is gaining due considerations over the past few years [4,28-31]. This remains a challenging topic as various mechanisms prevails and the subject is complex andstill under extensive scrutiny.

While in gas producing wells, the free acetic acid (HAc) content is physically dissolved from theproduced gas phase, in oil producing conditions free HAc is chemically produced from the reactionbetween dissolved CO2 and the acetate ions present in water.

In general term, organic acids change the solubility of corrosion product (i.e. dissolved iron, Fesat,at the saturation of corrosion product in FeCO3) and hence interfere with the formation of FeCO3

protective layer. This has a strong influence on CO2 corrosion and hence affects corrosivityassessment and prediction [4].

The synergistic interaction of the buffering reactions described earlier governs corrosivity. In CO2-H2S containing systems, the effect or organic acids is not yet fully known, although their role is

8

expected to be similar to the effect in CO2 systems and need to be accounted for in both chemical analyses as well as corrosion and predictions and mitigation.

EEffffeecctt ooff MMiiccrroossttrruuccttuurreeThere is limited data on the true effect of metal surfaces and steel microstructure on the

corrosion behaviour of H2S-CO2 corrosion. Data reported by Perdomo et. al. [32] showed differentbehaviour of API 5L X52 steel from API 5L Grade B. The corrosion rate for Grade B increased with increase in H2S, reached a maximum then decreased where for the X 52 steel the corrosion ratecontinued to increase for the ranges of H2S tested. The difference has been attributed to the less compact and less uniform FeS layer on the X52 steel. However, new generation of low carbonmicroalloyed 3%Cr steel, has shown improved properties compared with conventional grades of CLASs with enhanced CO2, H2S and O2 corrosion resistance, satisfactory sulphide stress cracking(SSC) performance together with more than acceptable mechanical properties [33-34].

EEffffeecctt ooff CCoorrrroossiioonn PPrroodduucctt SSccaalleessSmith and de Waard [35] reported the effectiveness of the corrosion product protective

scales that form even with small amount of H2S. The corrosion is effectively mitigated with the protective scales when combined with corrosion inhibitors. They reported corrosion rates below0.05 mm/y in the surface facilities of 25 gas fields that had H2S/CO2 ratio in the range of 1 to 750where downhole inhibitors injection was used. The piping and vessels were coated with a sulfiderich film even in areas where inhibitors carryover was expected to be minimal.

In support of other studies [14,17] Srinivasan and Kane [36] identified that the effect of H2S on CO2 corrosion depends on the ratio of CO2 to H2S. At low levels of H2S (< 0.01 psia) H2S has minimal or no influence on corrosion. At small amounts of H2S (CO2/H2S > 200) protective ironsulfide films form and reduce corrosion. Below 120º C, the dominant film is mackinawite and its formation depends on pH and temperature. In conditions where H2S is the dominant acid gas (partial pressure CO2/H2S < 200) meta-stable iron sulfide films form preferentially over FeCO3 scale in the range of 60 to 240º C. The protective film is initially mackinawite and at higher H2Sconcentration and temperature, the more stable pyrhotite iron sulfide forms which is moreprotective. At below 60 C and above 240º C the presence of H2S exacerbates corrosion since H2Sprevents the formation of the protective FeCO3 scale and the FeS scale becomes unstable andporous.

Pots et al [14] reported that testing at partial pressure ratio between 20 and 500 revealed that thehighest pitting corrosion rate was never worse than the sweet corrosion rate. The corrosionproduct films were a mixture of FeCO3 and FeS.

Irrespective of the CO2/H2S ratio, pyrite is the most stable ferrous sulfide in pure H2S or in mixedH2S/CO2.as seen in field removed samples. However, its stability may be locally jeopardized bygeneration of cathodically produced molecular hydrogen. Therefore, the degree of hydrogenevolution affects the nature of corrosion product in H2S containing conditions in which high H2

evolution results in high corrosion rate as it does not allow a protective layer to form readily. It isapparent that hydrogen transport needs to be taken on board when addressing protectiveness ofFeS layer. This is due to the fact that transport in the surface layer governs the liquid surfacestate, which in turn governs both corrosion rate and the solid surface state present in-situ or observed afterwards. A similar analogy has been made on the possible multiple steady statecorrosion rates in CO2 corrosion [37, 45].

NNoottaabbllee RReemmaarrkkssThe data in the literature and field experience clearly indicate that, in certain conditions the

presence of H2S leads to the formation and growth of FeS protective scale and decreases the corrosion rate. However, there is substantial evidence that this protective scale behaves in asimilar manner to FeCO3 in CO2 containing fluids [37,45] wherein protectiveness is not universaland certain conditions render it ineffective resulting in severe localised corrosion. The corrosionrates under these conditions can be significantly higher than the corrosion rates for CO2 corrosion

9

either measured or predicted [12,13,41-45]. The primary concern with the presence of H2S is the potential failure of the FeS protective scale and the risk of high pitting corrosion rate, as describedearlier.

The evidence also suggests that the data generated to date is still not sufficient to characterise the issues related to H2S-CO2 corrosion and the general understanding that in the presence of H2S,corrosion increases initially until the FeS scale forms and then the corrosion rate decreasessignificantly. This behaviour is not well defined such that it cannot be relied on for the selection ofmaterials since conditions may vary within the facility or during its operating life.

Nevertheless, the data in the literature clearly shows that corrosion inhibitors can be effective incontrolling H2S-CO2 corrosion if/when the correct inhibitor is selected to match the operatingconditions and is effectively deployed. Therefore, H2S-CO2 corrosion can be effectively controlledwith inhibition but requires that inhibitor selection and application be specific for the environmentof concern and not be based on pure CO2 or H2S.

MMAATTEERRIIAALLSS SSEELLEECCTTIIOONN SSTTRRAATTEEGGYY

There is a growing desire to have a corrosion design philosophy for production facilities totransport wet hydrocarbons. Such an approach can be used in the technical/commercialassessment of new field development and in prospect evaluation and for handling of sour fluids byfacilities not normally designed for sour service [39].

A universal method of preventing oilfield corrosion is through selection of the most appropriatematerial for a specific application. Optimum choice of materials is governed by a number of keyparameters including adequate mechanical properties, corrosion performance, weldability (whereappropriate), availability and cost. The choice of material is governed by the nature of itsapplication and generally falls into two categories of production and injection. A simple chartoutlining the necessary steps in selection of materials is shown in Figure 6 [39]. This methodologycaptures a systematic approach to determining potential deployment of CLASs as the firstreference point. Having established the degradation rate of CLASs, the second, although key parameter, is its resistance to SSC in the presence of H2S. The majority of these steps are coveredelsewhere [1,2,39] and this section briefly outlines specific measures required to allow selection ofthe most appropriate materials for a particular duty.

In general there is no consensus on applicability of corrosion models to H2S-CO2 corrosion [38]. Some of the data gathered both in the field and in the laboratory indicate that the corrosion rate for H2S-CO2 corrosion is lower than the predicted corrosion rate for CO2 alone with localisedcorrosion rate rarely exceeding CO2 corrosion predicted rates. This suggests that use of CO2

corrosion prediction models, although conservative, may provide good estimate for the maximumcorrosion rate expected [12,22,24,36] when FeS scale is formed. Bearing these in mind, simple rules for the prediction of corrosion damage rate in H2S-CO2 containing streams are included inTable 2.

It should be noted that a major consideration in materials design strategy is careful attention toacid flow back. In these conditions, the effluents’ property may render it highly corrosive if notneutralised. It can contain very high chloride brine with low pH fluids and additionally unknownfluid chemistry. The prevailing FeS or FeCO3 scales might not be stable under such fluid chemistry.

MMAATTEERRIIAALLSS RROOUUTTEESS

A brief summary of materials selection route for different aspects of production is given inthis section acting as an overview guide in a holistic materials selection strategy. It is important tonote that while CLASs are chosen primarily based on their corrosion resistance with adequateresistance against SSC, CRAs are normally selected based on their resistance to environmentalcracking with secondary consideration to their general corrosion behaviour. These include SSC and Cl-SCC (chloride stress corrosion cracking) or a combination of these types of damage as affectedby the operating temperatures [2,3]. The exception to this overview for CRAs is under extreme

10

conditions (a combination of high temperature, low pH, high CO2 and H2S) where general corrosionmay have to be considered in the overall selection strategy.

DDoowwnnhhoollee aanndd WWeellll HHeeaaddssSelection of materials for these applications are typically controlled by the need for

resistance to both corrosion and to SSC. The latter is important even at low levels of H2S due to the high pressure and the need for long term reliability to avoid potential safety risks andunnecessary workover costs. Uses of low alloy steels with continuous inhibition for low tomoderate corrosive conditions have proven to be successful in certain conditions. However, such systems can often prove impractical or too costly (e.g. deepwater subsea developments) such that they are not always the best approach. For highly corrosive conditions CRAs remain the most effective and economic option.

FFlloowwlliinneess aanndd UUnnpprroocceesssseedd FFlluuiiddss PPiippeelliinneess

Two scenarios are considered here:

ii.. Highly Corrosive or High Risk applications

For these applications CRAs often remain the most cost effective option since the risk of corrosion failure is high and use of corrosion inhibition with carbon and alloy steels is ofteneither impractical, costly or poses too high a risk.

iiii.. Low to Moderate Corrosiveness or Low Risk applications

CLAS with corrosion inhibition or pH stabilisation is an effective option. The corrosioninhibitor must be selected appropriately in accordance with field conditions and operatingparameters. On-line corrosion monitoring and frequent pigging may be required to ensure effective inhibition and inhibitor replenishments particularly where deposits may drop or accumulate within the flowlines (velocity of the fluids below the entrained velocity). Non-metallic liners have been used successfully to reduce failures and inhibition cost with HDPEand special grades of Nylon (Rilsan), although the limits of applicability for such liners needsto be taken into account.

PPrroocceessss FFaacciilliittiieess

In general, process facilities will require the same materials selection and corrosionmitigation strategy as pure H2S with vessels requiring internal corrosion barriers to prevent under deposit corrosion and corrosion inhibition for carbon steel components. Selection of organiccoatings vs. CRA cladding will depend on the corrosivity of the processed fluids and the potentialimpact of H2S presence on degradation of organic coatings such as blistering, etc.

Heat exchangers particularly gas coolers will require CRA material at minimum for the heat exchanger tubes and heads or shell depending on the design of the unit.

Process piping can be either CRAs or CLASs with corrosion inhibition (depending upon the pipingconfiguration, quantities, etc,) except for high temperature areas (> 100oC) where CRAs are more suitable. Non-metallic materials such as HDPE, FRP and lined piping are practical alternatives forproduced water handling and are becoming more widely used.

GGaass TTrreeaattiinngg PPllaannttss

Except for the high corrosive sections of the plants such as amine towers, glycol reboilersand gas coolers where cladding or solid CRAs is required, carbon and alloy steels with corrosioninhibition are acceptable options.

EExxppoorrtt PPiippeelliinneess

Export pipelines for systems with significant level of H2S and CO2 requires the use of inhibited CLASs to mitigate any corrosion that may occur.

11

SSeeaallss aanndd EEllaassttoommeerrss

H2S even at low concentration can cause severe degradation to elastomers and increasesthe propensity for elastomers embrittlement and explosive decompression. Selection of seals andelastomers for H2S/CO2 environments must follow the same selection guidelines for pure H2Senvironments.

CCOONNCCLLUUSSIIOONNSS

The review and analyses captured in the present paper demonstrate that the current understanding of combined H2S-CO2 corrosion is far from complete and many of the issues affecting its occurrence remain unresolved. The current state of knowledge points to the following conclusions:

1. In the combined presence of CO2 and H2S, there is a competitive interaction between FeCO3

and FeS corrosion products that may lead to affording protection or breaching the layers withresultant progressive localised corrosion

2. Subject to the type and nature of the corrosion product, H2S may lead to an increase in CO2

corrosion until certain concentration threshold after which weight loss corrosion may be reduced and in many cases results in a significant reduction. The integrity of the FeSprotective layer may be affected by the operating conditions. In this, it is more accurate toconsider that it is the mechanism of protectiveness which determines the nature of the soliddeposit, rather than the opposite

3. The CO2/H2S ratio is an acceptable means of categorising metal loss corrosion damage causedin the combined presence of H2S and CO2 – this ratio affects the nature of corrosion product and together with other key operational parameters can be considered in corrosion predictionmodels

4. A systematic materials optimisation strategy has been introduced integrating key parametersof past successes, present understanding of corrosion processes in hydrocarbon production, whole life costing and application regime of conventional as well as proprietary grades hence allowing the selection of the most suitable, safe and economical material option and corrosion control procedures

5. H2S-CO2 corrosion damage can be mitigated with a correct materials selection strategy andimplementation of corrosion control measures. In this, appropriate corrosion inhibitors have shown effective mitigating measures

6. While CLASs are chosen primarily based on their corrosion resistance with adequate resistance against SSC, CRAs are normally selected based on their resistance to environmental cracking with secondary considerations to their general corrosion behaviour

7. There remains a need to develop clear understanding of H2S-CO2 corrosion process and theinteraction of other key environmental, metallurgical and hydrodynamic parameters affectingthe phenomenon and the formation of corrosion products. The interaction between theseparameters is a key to determining their accumulative effect and means of mitigation througheffective materials selection and corrosion control strategy.

AACCKKNNOOWWLLEEDDGGEEMMEENNTTSS

Thanks are due to Mr Dominic Paisley (BP) for his contribution to the development of this paper. Valuable comments and contributions from Dr Jean Louis Crolet (Consultant) and Mr Don Harrop(BP) are highly appreciated.

RREEFFEERREENNCCEESS

1. M B Kermani and A Morshed, Corrosion Vol. 59 No. 8, 2003, p.659 – 683.2. M B Kermani, Paper No 00156, NACE, Orlando, March 2000

12

3. Petroleum and natural gas industries – Materials for use in H2S containing environments in oil and gas productionISO 15156, Parts 1-3, 2003

4. M R Bonis and J L Crolet, NACE Annual Corrosion Conference, Paper 05272, 2005 5. J L Crolet, Eurocorr 2004, (London UK; The Institute of Materials, 2004) 6. Metals Handbook, “Corrosion”, Volume 13 (ASM International, Materials Park, Ohio, 1987), p. 1233.7. B Craig, SPE Monograph Volume 15, Society of petroleum Engineers, Richardson, Texas, p. 22-29, 19938. R H Hausler, NACE Annual Corrosion Conference Paper No. 04732, 20049. R.N. Tuttle, Journal of Petroleum Technology, p 756-762, 1987 10. L W Jones, Corrosion and Water Technology for Petroleum Producers; OGCI, Tulsa, 1988 11. CO2 Corrosion Control in Oil and Gas Production - Design Considerations, eds. M B Kermani and L M Smith, European

Federation of Corrosion Publication No 23, 1997.12. N N Bich and K Goerz, NACE Annual Corrosion Conference, Paper No 26, 199613. N N Bich, “Fundamental of Wet Sour Gas Corrosion”, Presentation/Private communication, 1999 14. F M Pots, R C John, I J Rippon, M J J Simon Thomas, S D Kapusta, M M Girgis and T Whitman, NACE Annual Corrosion

Conference, Paper 02235, 200215. S N Smith and R.S. Pakalapati, NACE Annual Corrosion Conference, Paper 04744, 200416. J L Crolet, private communications, 2005 17. A K Dunlop, H L Hassell and P R Rhodes, NACE Annual Corrosion Conference, Paper No 46, 1983 18. A K Agrawal, C Durr and G H Koch, NACE Annual Corrosion Conference, Paper 04383, 200419. S N Smith and J L Pacheco, NACE Annual Corrosion Conference, Paper 02241, 2002 20. Z Foroulis, Werkstoffe and Korrosion, pp.463-470,198021. P R Russ and C Rainsford, SPE Asia Pacific Oil and Gas Conference and Exhibition, Paper No 88570, October 2004 22. L M Smith and C de Waard, NACE Annual Corrosion Conference, Paper 05648, 2005 23. B Brown, S R Parakala and S Nesic, NACE Annual Corrosion Conference, Paper 04736, 200424. D Paisley, BP Internal Report, 199325. C de Waard and U Lotz, NACE Annual Corrosion Conference, Paper No. 69, 1993 26. B Brown and S Nesic, NACE Annual Corrosion Conference, Paper 05625, 2005 27. I H Omar, Y M Gunaltun, J Kvarekval and A Dugstad, NACE Annual Corrosion Conference, Paper 05300, 2005 28. J A Dougherty, NACE Annual Corrosion Conference, Paper 04376, 200429. M W Joosten, J Kolts, J W Hembree and M Achour, NACE Annual Corrosion Conference, Paper 02294, 2004 30. M W Joosten, G D Harris, R L Hudgins, D A Daniels, and K M Cloke, NACE Annual Corrosion Conference, Paper 05114,

Corrosion 2005 31. W M Hedges and L McVeigh, NACE Annual Corrosion Conference, Paper No 21, 1999 32. J J Perdomo, J L Morales, A Viloria and A J Lusinchi, Materials Performance, pp 54-58, March 2002 33. M B Kermani, J C Gonzales, G L Turconi, T Perez and C Morales, NACE Annual Corrosion Conference, Paper 04111,

200434. L Pigliacampo, J C Gonzales, G L Turconi, T Peres, C Morales and M B Kermani, NACE Annual Corrosion Conference,

Paper 06133, 2006 35. L M Smith and C de Waard, Industrial Corrosion, p 14-18, 2004.36. S Srinivasan and R D Kane, NACE Annual Corrosion Conference, Paper No. 11, 1996 37. J L Crolet, S Olsen, W Wilhelmsen, NACE Annual Corrosion Conference, Paper 127, 1995 38. R Nyborg, NACE Annual Corrosion Conference, Paper 02233, 2002 39. M B Kermani, J C Gonzales, G L Turconi, T Perez and C Morales, NACE Annual Corrosion Conference, Paper 05111,

200540. J L Crolet and M R Bonis, SPE Production Engineering, pp. 449-453, Nov, 1991 41. A Ikeda, M Ueda and S Mukai, Advances in CO2 Corrosion Volume 2, pp 1-22, NACE International, 198542. K. Videm and J. Kvarekval, NACE Annual Corrosion Conference, Paper No. 94012, 199443. J Kvarekval, EUROCORROSION 97, Trondheim, Norway.44. A Valdes, R Case, M. Ramirez and A. Ruiz, NACE Annual Corrosion Conference, Paper No. 22, 1998 45. J L Crolet, in “Modelling Aqueous Corrosion From Individual Pits to System Management”, ed. K R Trethewey and P R

Roberge, NATO ASI Series, Series E: Applied Sciences, Vol 266, pp 1-28, 1994.

13

Table 1

The analysis of the synthetic produced waters used in the tests

Component Formation Water(ppm)

Chloride ContainingFluid

(ppm)Chloride 52,000 42500SO4

-- 10Bicarbonate 500Sodium 29,500 27540Potassium 380Calcium 3200Magnesium 500Acetate 50pH 5.5-5.8 3.8-4.0

Table 2 H2S-CO2 Corrosion Dominance and Prediction Guides (A Rule of Thumb)

CO2/H2SRatio

Subcategory

OperatingParameters

DominatingCorrosionProcess

PrimaryCorrosionProduct

Possible Pattern ofCorrosion Damage

CorrosionDamage Risk

Factor(A Rule ofThumb)

< 20 - Known H2S FeS

Low:Subject to theformation of a protective FeS

-

20 to500

KnownMixedH2S/CO2

FeS andFeCO3

Mixed - the highestlocalised corrosion rate does not exceedpredicted sweet corrosion rate.

CO2 CorrosionModel

100 Fully knownMixedH2S/CO2

FeS andFeCO3

Mixed – Corrosion rate determined bythe nature of FeS

CO2 CorrosionModel withpossiblereduction of 4

> 500 Known CO2 FeCO3 CO2 driven

CO2 CorrosionModel withpossiblereduction of 4

1000 Fully known CO2 FeCO3 CO2 driven

CO2 CorrosionModel withpossiblereduction of 3

10000 Fully known CO2 FeCO3 CO2 driven

CO2 CorrosionModel withpossiblereduction of 3

>10000 Fully known CO2 FeCO3 CO2 driven CO2 CorrosionModel

14

Figure 1. Comparative corrosiveness of three common gases in water solutions (25oC, 5-7 day exposure, 2-5 g/litre NaCl, HCO3 alkalinity < 50 mg/l – computed from several datasources) [after Ref 11].

Figure 2. CO2-H2S corrosion domains [after Ref 14].

15

Figure 3. Parameters affecting CO2-H2S corrosion.

Figure 4. Corrosion rate of X65 linepipe steel under sweet and mildly sour conditions in chloridecontaining conditions at pH 3.8-4.0 [24].

16

Figure 5. Corrosion rate of X65 linepipe steel under sweet and mildly sour conditions insimulated formation water at pH 5.5-5.8 [24].

17

Fig

ure

6.

Mat

eria

ls o

ptim

isat

ion s

trat

egy

flow

char

t [a

fter

Ref

39].

18