corrosion environmental parameters - 2001 web.rip, (p.23)

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Predict Help - Environmental Parameters

CO2-based corrosion has been one of the most active areas of research, with several predictive models

or carbon steel corrosion assessment. These efforts range from a predictive model that begins with

CO2 corrosion to models that focus on specific aspects of the corrosion phenomena (such as flow-

nduced corrosion or erosion corrosion) to models that empirically relate corrosion rates to gas

roduction and water production rates.

The Predict model integrates lab data and field experience within the framework of relevant

ontrolling parameters that are most prominent in oil and gas production. While there have been

everal studies focusing on the exact mechanism of metal dissolution in CO2 containing waters, the

fforts of De Waard and Milliams and others present a commonly accepted representation wherein

nodic dissolution of iron is a pH dependent mechanism as given by Bockris, the cathodic process is

riven by the direct reduction of undissociated carbonic acid. These reactions can be represented as,

Fe ----------> Fe++ + 2e-(Anodic reaction)

H2CO3 + e-----> HCO3- + H (Cathodic reaction)

The overall corrosion reaction can be represented as,

Fe + 2H2CO3 ---> Fe++ + 2 HCO3- + H2

The build up of the bicarbonate ion can lead to an increase in the pH of the solution till conditions

romoting precipitation of iron carbonate are reached, leading to reaction given below:

Fe + 2HCO3- ---> FeCO3+ H2O+CO2

ron carbonate solubility, which decreases with increasing temperature, and the consequent

recipitation of iron carbonate is a significant factor in assessing corrosivity. This corrosion rate

quation is given as2,

log (Vcor) = 5.8 - 1710/T + 0.67 log (pCO2) ------ (1)

where

Vcor = corrosion rate in mm/yr

T = operating temperature in K

pCO2 = partial pressure of CO2 in bar

The corrosion rate obtained by equation (1) has typically been often seen as the maximum possible

orrosion rate without accounting for iron carbonate scaling. A nomogram representing eq. (1) is given

n Figure 1, which also includes a scale factor to account for the formation of protective carbonate

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ilms that lead to a reduced corrosion rate at higher temperatures.

H (Hydrogen Ion Concentration)

H is one of the most critical parameters in corrosivity determination. For production environments,

where it is the dissolved CO2 or H2S that contribute significantly to a lower pH, pH can be determined

s a function of acid gas partial pressures, bicarbonates and temperature, as shown in Figure 3 [23].

From a practical stand point, the contribution of H2S or HCO3 or temperature to pH determination is

nother way of representing effective levels of CO2 that would have produced a given level of pH.

While it has been documented that the CO2 corrosion mechanism is dissimilar to that of strong acids

ke HCl (where as CO2 corrosion is now understood to progress through direct reduction of H2CO3 to

HCO3- rather than reduction of H+ ions), and that carbonic acid corrosion is much more corrosive than

hat obtained from a strong acid such as HCl at the same pH, there is also significant agreement that

ower pH levels obtained from higher acid gas presence leads to higher corrosion rates. Conversely,

igher levels of pH obtained through buffering in simulated production formation water solutions have

een shown to produce significantly lower corrosion rates even at higher levels of CO2 and/or H2S.

Data about the effects of pH from another study is shown in Figure 4. Hence, it is more meaningful to

etermine the effective CO2 partial pressure from the system pH. Data in Figure 3 can be represented

s equations for straight lines in terms of pH and acid gas partial pressures for a given level of HCO3

nd temperature. The Predict system incorporates a numerical computer model to compute pH for

ifferent values of acid gas partial pressures, HCO3 and temperature.

Hydrogen Sulfide (H2S)

Oilfield production environments, in recent years, have been characterized by increasing presence of

H2S and related corrosion considerations. Even though H2S is probably the most significant concern in

urrent day corrosion and cracking evaluation, the role of H2S in corrosion in steels has received much

ess attention when compared to the widely studied CO2 corrosion. However, H2S related corrosion

nd cracking has remained one of the biggest concerns for operators involved in production because of

he significance of H2S related damage.

The Predict model, in addition to its contribution in pH reduction, provides a three fold role for H2S:

1. At very low levels of H2S (< 0.01 psia), CO2 is the dominant corrosive species, and at

temperatures above 60 C, corrosion and any passivity is a function of FeCO3 formation related

phenomenon and the presence of H2S has no realistic significance.

2. In CO2 dominated systems, presence of even small amounts of H2S (ratio of pCO2/pH2S > 200),

can lead to the formation of an iron sulfide scale called mackinawite at temperatures below 120

C. However, this particular form of scaling, which is produced on the metal surface directly as afunction of a reaction between Fe++ and S- - is influenced by pH and temperature. This surface

reaction can lead to the formation of a thin surface film that can mitigate corrosion. The

stability and formation of such films called mackinawite is the subject of much research.



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3. In H2S dominated systems (ratio of pCO2/pH2S < 200), there is a preferential formation of a

meta-stable sulfide film in preference to the FeCO3 scale; hence, there is protection available

due to the presence of the sulfide film in the range of temperatures 60 to 240 C. Here, initially it

is the mackinawite form of H2S that is formed as a surface adsorption phenomenon. At higher

concentrations and temperatures, mackinawite becomes the more stable pyrhotite. However, at

temperatures below 60 C or above 240 C, presence of H2S exacerbates corrosion in steels since

the presence of H2S prevents the formation of a stable FeCO3 scale. Further, it has beenobserved that FeS film itself becomes unstable and porous and does not provide protection.

Also, the scale factor applicable for CO2 corrosion with no H2S (shown in Figure 1) becomes

inapplicable. Even though there is agreement amongst different workers that there is a

beneficial effect of adding small amounts of H2S at about 60 C, Ikeda et al.[9] and Videm et

al.[11] present divergent results at higher concentrations and higher temperatures.

The effect of H2S adopted in the Predict model reflects work published by T. Murata et al. for CO2

ominated systems. Figure 5 [29] shows the combined effects of temperature and gas composition on

orrosion rate of carbon steels. Figure 6 [9] shows the effect of varying degrees of H2S contamination

n CO2 corrosion. It is to be noted that the role of H2S in CO2 corrosion is a complex issue governed

y film stability of FeS and FeCO3 at varying temperatures and is an area further active research.

Bicarbonates

The bicarbonate ion is a buffering agent used in aqueous solutions to increase the pH of the solution.

ts presence is typically measured in mili-equivalents/liter (meq/l). One meq/l represents 0.061 grams

f HCO3 in one liter of solution. The reduction in pH in turn decreases the corrosivity of thenvironment.

Bicarbonates in the operating environment have a significant impact on corrosion rates. On one hand,

igh levels of bicarbonates can provide higher pH numbers leading to corrosion mitigation even when

he partial pressures of CO2 and H2S are fairly high. There is a natural inhibitive effect of presence of

icarbonates which can be present in substantial quantities in formation waters (up to 20 meq/l)31.

Condensed water in production streams typically contains no bicarbonates.

Chlorides

Produced water from hydrocarbon formations typically contains varying amounts of chloride salts

issolved in solution. The chloride concentration in this water can vary considerably, from zero to few

pm for condensed water to saturation in formation waters having high total dissolved salts/solids

TDS). In naturally deaerated production environments, corrosion rate increases with increasing

hloride ion content over the range 10,000 ppm to 100,000 ppm30. The magnitude of this effect

ncreases with increasing temperature over 60 C (150 F). This combined effect results from the fact

hat chloride ions in solution can be incorporated into and penetrate surface corrosion films which canead to destabilization of the corrosion film and lead to increased corrosion. This phenomenon of

enetration of surface corrosion films increases in occurrence with both chloride ion concentration and

emperature. Chlorides are often specified in ppm NaCl. It should be noted that ppm chlorides can be



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btained as 0.63 x ppm NaCl.

Under normal circumstances, the chloride content of the aqueous phase does not directly affect the

ydrogen charging conditions in steel. However, it can also affect the effectiveness of chemical

orrosion inhibitors. Therefore, in many cases, more careful selection of inhibitors and inhibition

rocedures must be performed where high levels of chlorides (>30,000 ppm) are present.

Corrosion rates of steel in oil and gas production generally increase with increasing chloride content.

The chloride species in the aqueous phase can work to penetrate and destabilize protective surface

ilms. Typically, brines with low chloride content (i.e.


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Care should be taken to evaluate presence of possible locations where water can separate from the

ydrocarbons and form a continuous water phase. Under such conditions, substantial corrosion can

xist.

Dew Point

n gas dominated systems, there are two measures to evaluate availability of the aqueous medium. Ifhe operating temperature is higher than the dew point of the environment, no condensation is going to

e possible and will lead to highly reduced corrosion rates. Corrosion under condensing conditions

i.e., operating temperature less than the dew point) is a function of the rate of condensation and

ransport of corrosion products from the metal surface. If the total water in a condensing system as

measured by the Water to Gas Ratio is less than 11.3m3/Mm3 (2 BBL water/MSCF gas), corrosivity is

ubstantially reduced. Hence the dew point plays a critical role in gas-dominated systems in that at

igher operating temperatures (greater than the dew point) significantly lower or no corrosion may be

bserved due to absence of condensed moisture.

Water Cut

The Predict model classifies systems as oil dominated or gas dominated on the basis of the gas/oil ratio

GOR) of the production environment. If the environment has a GOR < 890 m3/m3 (5000 scf/bbl in

English units)35, the tendency for corrosion and environmental cracking is often substantially reduced.

This is caused by the possible inhibiting effect of the oil film on the metal surface, which effectively

educes the corrosivity of the environment. However, the inhibiting effect is a function of the type of

il phase and the water cut of the environment. The persistence of the oil phase is a strong factor in

roviding protection, even in systems with high water cuts. In oil systems with a persistent oil phase

nd up to 45 percent water cut, corrosion is fully suppressed, irrespective of the type of hydro-carbon.

Relative wettability of the oil phase versus the water phase also has a significant effect on corrosion.

Metal surfaces that are water wet show significantly higher corrosion rates.

The degree of protection provided by oil films can be quantified only as a function of water cut and

elocity. Figure 10 [36] shows data that relates the acid number of the crude to oil wettability and

Figure 11 [36] shows corrosion rate as a function of produced water content for different crude

il/produced water mixtures. In oil systems the water cut acts in synergy with the oil phase toetermine the level of protection from the hydrocarbon phase. However, at very low water cuts (less

han 5 percent), corrosive severity of the environment is lessened due to the absence of an adequate

queous medium required to promote the corrosion reaction.

Oil Type

The Predict model classifies systems as oil dominated or gas dominated on the basis of the gas/oil ratio

GOR) of the production environment. If the environment has a GOR < 890 m3/m3 (5000 scf/bbl in

English units), the tendency for corrosion and environmental cracking is often substantially reduced.This is caused by the possible inhibiting effect of the oil film on the metal surface, which effectively

educes the corrosivity of the environment. However, the inhibiting effect is dependent on the oil phase

eing persistent and acting as a barrier between the metal and the corrosive environment. The



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ersistence of the oil phase is a strong factor in providing protection, even in systems with high water

uts. In oil systems with a persistent oil phase and up to 45 percent water cut, corrosion is fully

uppressed, irrespective of the type of hydro-carbon. Relative wettability of the oil phase versus the

water phase has a significant effect on corrosion. Metal surfaces that are oil wet show significantly

ower corrosion rates37.

The Predict system provides for a significant reduction in the corrosion rate (up to a factor of 4) based

n the type of oil phase being

q Highly persistent,

q mildly persistent

q not persistent.

However, the degree of protection can be quantified only as a function of water cut and velocity. The

ersistence determination is a more complex task and requires knowledge of the kerogen type and

ydrocarbon density. It is important to understand the type of crude oil in terms of the organicompounds that make up the crude to determine wettability effects. Figure 10 [36] shows data that

elates the acid number of the crude to oil wettability and Figure 11[36] shows corrosion rate as a

unction of produced water content for different crude oil/produced water mixtures. While the effect of

ersistence of the oil medium is significant on corrosion rates, it is even more difficult to quantify

recise compositional elements of an oil medium that contribute to wettability and persistent oil film

ormation. Such quantification is possible by rigorous laboratory testing of different actual,

ncontaminated (read deaerated) production water samples, so as to determine the extent of protection.

n oil systems the water cut acts in synergy with the oil phase to determine the level of protection fromhe hydrocarbon phase. However, at very low water cuts (less than 5 percent), corrosive severity of the

nvironment is lessened due to the absence of an adequate aqueous medium required to promote the

orrosion reaction.

Oxygen

Presence of oxygen significantly alters the corrosivity of the environment in production systems.

Oldfield [39] has chronicled how presence of oxygen can significantly increase corrosion rates due to

cceleration of anodic oxidation. While corrosion rate increases with oxygen, rate of oxygen reduction

s a cathodic reaction is further exacerbated by:

. Increase in operating temperature

. Increased fluid flow leading to increased mass flow of oxygen to the metal surface

. Increasing oxygen concentration

Data showing increases in corrosion rate as a function of oxygen concentration for differing

emperatures is shown in Figure 12. Corrosion rates for different flow velocities and oxygen levels as a

unction of temperature is shown in Figure 13.



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ulfur

n systems containing high levels of H2S, elemental sulfur is often found to be present. Its presence can

ignificantly increase the corrosivity of the production environment with respect to weight loss

orrosion and localized corrosion. Presence of sulfur is similar to that of having oxygen in production

ystems in that it can be a strong oxidizing agent and can lead to significantly increased local attack.ulfur can directly combine with Iron to form FeS and can lead to significant metal loss in a localized

mode.

Fluid Velocity

Next to the corrosive species that instigate corrosion, velocity is probably the most significant

arameter in determining corrosivity of production systems. Fluid flow velocities affect both the

omposition and extent of corrosion product films. Typically, high velocities (> 4 m/s for non-

nhibited systems) in the production stream leads to mechanical removal of corrosion films and thensuing exposure of the fresh metal surface to the corrosive medium leads to significantly higher

orrosion rates. Corrosion rate as a function of flow velocity and temperature is shown in Figure 8[15].

n multiphase (i.e. gas, water, liquid hydrocarbon) production, the flow rate influences the corrosion

ate of steel in two ways. First, it determines the flow behavior and flow regime. In general terms, this

s manifested as static conditions (i.e. little or no flow) at low velocities, stratified flow at intermediate

onditions and turbulent flow at higher flow rates. One measure which can be used to define the flow

onditions is the superficial gas velocity. In liquid (oil / water) systems, this is replaced with the liquid

elocity.

Velocities less than 1 m/s are considered static. Under these conditions corrosion rates can be higher

han those observed under moderately flowing conditions. This occurs because under static conditions,

here is no natural turbulence to assist the mixing and dispersion of protective liquid hydrocarbons or

nhibitor species in the aqueous phase. Additionally, corrosion products and other deposits can settle

ut of the liquid phase to promote crevice attack and underdeposit corrosion.

Between 1 and 3 m/sec, stratified conditions generally still exist. However, the increased flowromotes a sweeping away of some deposits and increasing agitation and mixing. At 5 m/sec,

orrosion rates in non-inhibited applications start to increase rapidly with increasing velocity.31 Data

hown in Figure 9[31] demonstrates the effects of velocity on corrosion rate for both inhibited and non-

nhibited systems. For inhibited applications, corrosion rates of steel increase only slightly between 3

o 10 m/sec, resulting from mixing of the hydrocarbon and aqueous phases. Above about 10 m/sec,

orrosion rates in inhibited systems start to increase due to the removal of protective surface films by

he high velocity flow.

Flow related effects on corrosivity have been linked to the wall shear stress developed and is an area ofntense research in the community. Flow induced corrosion is a direct consequence of mass and

momentum transfer effects in a dynamic flow system where the interplay of inertial and viscous forces

s responsible for accelerating or decelerating metal loss at the fluid/metal interface. While flow-



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nduced corrosion is a significant component of predictive modeling discussed herein, the topic of flow-

elated effects is being actively researched by the authors and forms the focus of another publication.

Another relevant aspect of flow or velocity induced corrosion is erosion corrosion and refers to the

mechanical removal of corrosion product films through momentum effects or through impingement

nd abrasion. Guidelines for velocity limits with respect to erosional considerations are given in API-

4E in terms of the density of the fluid medium.

Corrosion Allowance

n designing systems from materials such as steel which can exhibit corrosion, it is common to take

nto account and added factor of safety in terms of the Corrosion Allowance. The concept of Corrosion

Allowance involves the use of an increased thickness over that required for mechanical design to allow

or corrosion and metal loss that may take place during

q the project life or

q

until replacement.

The magnitude of the Corrosion Allowance is dependent on the severity of corrosion expected and the

bility to mitigate corrosion usually by the use of corrosion inhibitors. The Corrosion Allowance in

most cases is < 0.12 inches (3 mm). However, in some particularly severe cases larger Corrosion

Allowances can be utilized.

ervice Life

The Service Life is the period of useful service for a particular component. This is usually taken to behe time required to achieve a corrosion metal loss equal to the Corrosion Allowance. Alternatively,

he Service Life may be used to define the required Corrosion Allowance based on the assessment of

orrosion severity and inhibition performance and methods in the particular application.

Type of Flow

The flow conditions (i.e. static, stratified, turbulent, etc.) are dependent on the nature of the produced

ases and fluids and if the flow is primarily horizontal (surface production) or vertical (subsurface

roduction). Horizontal flow is usually more prone to static and stratified conditions which limits the

mount of mixing of oil and water phases at low flow rates. Vertical flow typically exhibits these types

f conditions only during period of shut-in of the well. See fluid velocity for more information.

Method of Inhibition

For horizontal flow systems the following types of inhibition method are commonly used:

No Treatment - The conditions may be essentially non-corrosive. This usually occurs under theollowing conditions (a) very low acid gas (CO2 and H2S) partial pressures, (b) low amounts of water

r (c) very persistent oil phase.



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ystems. Inhibition has been typically found to be viable in flows with velocity in the range 0.3 - 10

m/s. Inhibition Efficiency (IE) describes the efficacy of an inhibitor treatment in mitigating weight loss

orrosion and is an important factor in assessing corrosivity. It is based on either laboratory or field

ata where inhibited and non-inhibited corrosion rates are compared using the following equation:

IE = 100[(CRn - CRi)/CRn]

where

CRn = non-inhibited corrosion rate,

CRi = inhibited corrosion rate.

Values of IE near 1.0 represent conditions with maximum efficacy of the inhibitor reatment.

Conditions which affect IE include:

1. Inhibitor concentration.

2. Severity of corrosive environment.

3. Service temperature.

4. Solubility of inhibitor in aqueous phase.

5. Phase behavior of inhibitor and carrier fluid in service environment.

6. Persistence of inhibitor on metal surface.

The predictive model evaluates inhibition efficacy on the basis of velocity, hydrocarbons to water rationd dissolved chloride levels. The method of delivery (batch, continuous, pigging etc.) is also an

mportant factor in determining appropriateness of inhibition for a given set of operating conditions.



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corrosion environmental parameters - 2001 web.rip, (p.23)

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