CO2 Corrosion in Oil - Part 2

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6/9/13 Chemical & Process Technology: CO2 Corrosion in Oil & Gas - Part 2

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CO2 Corrosion in Oil & Gas - Part 2 [1]

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useful article related to CO2 corrosion in Oil & Gas.

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Use of artificial neural networks for predicting crude oil effect on CO2 corrosion

of carbon steels [6]

The role of crude oil on CO2 corrosion has gained special attention in the last

few years due to its significance when predicting corrosion rates. However, the

complexity and variability of crude oils makes it hard to model its effects, which

can influence not only wettability properties but also the corrosivity of theassociated brine. This study evaluates the usefulness of Artificial Neural

Networks (ANN) to predict the corrosion inhibition offered bycrude oils as a

function of several of their properties which have been related in previous

studies to the protectiveness of crude oils, i.e. nitrogen and sulfur contents,

resins and asphaltenes, TAN, nickel and vanadium content, etc. Results showed

that neural networks are a powerful tool and that the validityof the results is

closely linked to the amount of data available and the experience and

knowledge that accompany the analysis.

A Stochastic Prediction Model of Localized CO2 Corrosion [7]

In this paper a two-dimensional (2-D) stochastic localized CO2 corrosion model

is proposed, which describes the balance of two processes: corrosion (leading to

metal loss) and precipitation (leading to metal protection). The model is able to

predict localized corrosion of carbon steel in CO2 containing environments. The

model uses corrosion rate and surface-scaling tendency predicted by a 1-D
http://www.corrosioncenter.ohiou.edu/documents/05554.pdfhttp://www.corrosioncenter.ohiou.edu/documents/05554.pdfhttp://www.corrosioncenter.ohiou.edu/documents/05554.pdfhttp://webwormcpt.tradepub.com/free/wup/prgm.cgihttp://webwormcpt.blogspot.com/2008/07/tips-on-succession-in-free-subscription.htmlhttp://webwormcpt.blogspot.com/2008/10/co2-corrosion-in-oil-gas-part-1.htmlhttp://webwormcpt.blogspot.com/2008/10/co2-corrosion-in-oil-gas-part-2.htmlhttp://webwormcpt.blogspot.com/2008/10/co2-corrosion-in-oil-gas-part-2.htmlhttp://webwormcpt.blogspot.com/2008/10/co2-corrosion-in-oil-gas-part-2.htmlhttp://www.corrosioncenter.ohiou.edu/documents/05057.pdfhttp://www.corrosioncenter.ohiou.edu/documents/05554.pdfhttp://webwormcpt.tradepub.com/free/wup/prgm.cgihttp://webwormcpt.blogspot.com/2008/07/tips-on-succession-in-free-subscription.htmlhttp://webwormcpt.blogspot.com/2008/10/co2-corrosion-in-oil-gas-part-1.htmlhttp://webwormcpt.blogspot.com/2008/10/co2-corrosion-in-oil-gas-part-2.htmlhttp://webwormcpt.blogspot.com/2008/10/co2-corrosion-in-oil-gas-part-2.html


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mechanistic corrosion model as the inputs. It can predict the possibility of

localized corrosion as a function of primitive parameters such as temperature,

pH, partial pressure of CO2, velocity, etc. The maximum pit penetration rate as

well as the uniform corrosion rate can be predicted and used to describe the

severity of the localized attack.

The effect of trace amount of H2S on CO2 corrosion investigated by using the

EIS technique [8]

A project has been initiated with the aim of extending the model to cover the

effect of H2S on CO2 corrosion. This report covers one of the main building

blocks necessary to complete the mechanistic CO2/H2S corrosion model,

namely, electrochemistry of API 5L X65 carbon steel CO2 corrosion in the

presence of small amounts of H2S (less than 340ppm). The corrosion process

monitored by Linear Polarization Resistance (LPR) and Electrochemical

Impedance Spectroscopy (EIS) showed a significant decrease in corrosion rate in

the presence of H2S due to the metal surface coverage by a sulfide film. This

sulfide film was identified as mackinawite by X-ray photoelectron spectroscopy

(XPS). Since the experimental results suggested that the mechanism is a

retardation of the charge transfer process, the surface coverage was calculated

from the corrosion rate. The Langmuir-type adsorption isotherm was successful

in modeling the surface coverage by mackinawite in the presence of trace

amounts of H2S.

Iron carbonate scale formation and CO2 corrosion in the presence of acetic acid

[9]

The role of acetic acid (HAc) on X-65 mild steel carbon dioxide (CO2) corrosion

has been investigated in the presence of iron carbonate scale (FeCO3). Free HAc

is known to be a source of hydrogen ions and to lead to an increase in mild steel

corrosion rates, especially at low pH values. Protective iron carbonate scales

form at high temperatures (more than 60C) and high values of pH. Aninteresting situation occurs when free HAc and protective FeCO3 scale co-exist.

Numerous studies have looked at HAc and FeCO3 scale effects separately, but

there is little knowledge of how the protectiveness of FeCO3 scale will be

affected, in the presence of acetic acid. Some reports suggested FeCO3 scale

thinning and loss of protection in the presence of HAc Thus in order to clarify

this aspect of CO2 corrosion, the effect of HAc on FeCO3 scale protectiveness

using 3 wt % NaC1 salt solution at T = 80C has been studied under stagnant
http://www.corrosioncenter.ohiou.edu/documents/05295.pdfhttp://www.corrosioncenter.ohiou.edu/documents/05630.pdf


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conditions. No effect of HAc on FeCO3 scale protectiveness was found over a

range of pH and HAc concentrations.

Use and Abuse of EIS in Studying the Mechanisms of CO2/H2S Corrosion of Mild

Steel [10]

Electrochemical Impedance Spectroscopy (EIS) is a powerful transient technique

which enables an insight into the corrosion process not easily obtained by

other predominantly DC techniques. However the EIS technique presents a large

challenge both from a theoretical as well as an experimental point of view.

Collecting accurate EIS raw data is not easy as EIS is plagues with errors not

seen by the DC techniques. Building mechanistic models to capture the EIS data

is a very complex task which enables extraction of valuable information about

the corrosion process, however the time and effort investment required is very

large. In this study of CO2/H2S corrosion of mild steel it was found that a

minor detail in the experimental set-up caused erroneous acquisition of EIS

raw data. These data were successfully modeled by using a complex

electrochemical theory, which appeared plausible. When the experimental

mistake was discovered the EIS data were retaken, the analysis was redone and

the conclusions about the corrosion process were completely revised.

Kinetics of Iron Sulfide and Mixed Iron Sulfide/Carbonate Scale Precipitation in

CO2/H2S Corrosion [11]

Glass cell experiments were conducted to investigate kinetics of iron sulfide and

mixed iron sulfide/carbonate scale precipitation in CO2/H2S corrosion. Weight

gain/loss (WGL) method was used to investigate the scale formation using X65

carbon steel as substrates. Scanning Electron Microscopy (SEM/EDS), X-ray

Diffraction methodology (XRD), X-ray Photoelectron Spectroscopy (XPS), and

Electron Probe Micro-analyzer (EPMA) were used to analyse the scale. The

experimental results show that the corrosion products formed in CO2/H2S

system depend on the competitiveness of iron carbonate and mackinawite. Athigh H2S concentration and low Fe2+ concentration, mackinawite was the

predominant scale formed on the steel surface. At low H2S concentration and

high Fe2+ concentration, both iron carbonate and mackinawite form. It was also

found that ferrous ions forming mackinawite scale mainly come from Fe2+

released from the steel surface.

Experimental Study on Water Wetting and CO2 Corrosion in Oil-Water Two-
http://www.corrosioncenter.ohiou.edu/documents/06595.pdfhttp://www.corrosioncenter.ohiou.edu/documents/06595.pdfhttp://www.corrosioncenter.ohiou.edu/documents/06644.pdfhttp://www.corrosioncenter.ohiou.edu/documents/06417.pdf


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Phase Flow[12]

Internal corrosion occurs only when corrosive water wets the pipe inner wall.

However, water wetting is one of most important missing links of our current

overall understanding of internal corrosion of oil and gas pipelines. In this

study, extensive experimental studies on water wetting in large diameter

horizontal oil water pipe flows were carried out. Four main techniques (wall

conductance probes, Fe2+ concentration monitoring, wall sampling and flow

pattern visualization) were used to determine phase wetting on the internal

wall of pipe at different superficial oil and water velocities. Four flow patterns

were observed : stratified flow, stratified flow with mixed layer, semi-dispersed

and dispersed flows. Three types of phase wetting regimes (water wetting,

intermittent wetting and oil wetting) were determined. A comprehensive phase

wetting map was obtained based on the overlapping information from these

techniques.

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CO2 Corrosion of Carbon Steel in High Ionic Strength Brine Solution [15]

The general CO2 corrosion rates of C1018 carbon steel have been measured forNaCl concentrations 3 25 wt% at 5C, pH4.0. The corrosion process was

monitored by linear polarization resistance and potential dynamic sweeps.

Experimental results show that high salt concentrations affect the general CO2

corrosion rate significantly and nonlinearly. Potentiodynamicsweep analysis

shows that the high content of salt retards both cathodic and anodic process.

No significant effects of velocity on corrosion rates are seen for various saline

conditions

Basics Revisited - Kinetics of Iron Carbonate Scale Precipitation in [16]CO2 [17]

Corrosion [18]

Glass cell experiments were conducted to understand kinetics of iron carbonate

scale formation in pure carbon dioxide (CO2) corrosion of mild steel. Weight

gain and loss (WGL) method was used as a direct approach to investigate

kinetics of scale formation. The experiments were done at the temperatures of
http://www.corrosioncenter.ohiou.edu/documents/06595.pdfhttp://www.corrosioncenter.ohiou.edu/documents/06365.pdfhttp://www.corrosioncenter.ohiou.edu/documents/06372.pdfhttp://www.corrosioncenter.ohiou.edu/documents/06365.pdfhttp://www.corrosioncenter.ohiou.edu/documents/06372.pdfhttp://webwormcpt.tradepub.com/free/upst/prgm.cgihttp://webwormcpt.blogspot.com/2008/07/tips-on-succession-in-free-subscription.htmlhttp://www.corrosioncenter.ohiou.edu/documents/06595.pdf


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60oC to 90oC, and an iron carbonate supersaturation range of 12 to 350. It is

found that the calculated results obtained by the previous kinetics expressions

using the traditional dissolved ferrous ion concentration method are one to two

orders of magnitude higher than the experimental precipitation rates obtained

in the present study by the WGL method. The results show that the main source

of the ferrous ions which are involved in formation of the protective iron

carbonate scale is the iron dissolution process. It has been clearly demonstratedthat the precipitation rate of iron carbonate is directly related to the conditions

at the steel surface which can frequently be very different from the one in the

bulk fluid.

Case Base Reasoning Model of CO2 Corrosion Based on Field Data [19]

An important aspect in corrosion prediction for oil and gas wells and pipelines

is to obtain a realistic estimate of the corrosion rate. Corrosion rate prediction

involves developing a predictive model that utilizes commonly available

operational parameters, existing lab/field data and theoretical models to obtain

realistic assessments of corrosion rates. The Case-based Reasoning (CBR) model

for CO2 corrosion prediction is designed to mimic the approach of experienced

field corrosion personnel. The model takes knowledge of corrosion rates for

existing cases and uses CBR techniques and Taylor series expansion to predict

corrosion rates for new fields having somewhat similar parameters. The

corrosion prediction using CBR model is developed in three phases: case

retrieval, case ranking, and case revision. In case retrieval phase, the database of

existing cases is queried in order to identify the group of cases with similar

values of critical corrosion parameters. Those cases are ranked in the second

phase, using a modified Taylor series expansion of the corrosion function

around each case. The most similar case is passed to the third phase: case

revision. The correction of the corrosion rate by using a mechanistic corrosion

model is utilized in order to predict the corrosion rate of the problem under

consideration. The (CBR) model has been implemented as a prototype and

verified on a large hypothetical case database and a small field database with

real data.

Investigation of the Localized CO2 corrosion Mechanism [20]

Localized CO2 corrosion on mild steel is always associated with the partial

breakdown of a protective corrosion product scale such as iron carbonate. The

scale breakdown can happen for a variety of reasons many of them related to
http://www.corrosioncenter.ohiou.edu/documents/07323.pdfhttp://www.corrosioncenter.ohiou.edu/documents/07553.pdf


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fluid flow. It is hypothesized that following the scale damage, a galvanic effect is

established between the scale covered surface (cathode) and the scale free

surface (anode) leading to propagation of localized attack. To test this

hypothesis, in a series of laboratory experiments, an iron carbonate scale is

formed by a repeatable process. Subsequently, in the so called scale removal

tests the breakdown of the scale under flowing conditions is investigated. The

results show that the iron carbonate scale can be partially removed bymechanical stresses, chemical dissolution or by both mechanisms acting

simultaneously. In another series of experiments, a newly developed artificial

pit test is used to investigate the propagation of localized CO2 corrosion via a

galvanic coupling. The artificial pit is composed of a large cathode covered by

protective iron carbonate scale, and a small bare steel anode. The two are

electrically isolated and connected by a zero resistance ammeter to measure the

galvanic current during the tests. The results have confirmed the galvanic

mechanism for localized CO2 corrosion propagation. It has been demonstratedthat pits will propagate only if the conditions are just right: the solution is

neither under-saturated nor heavily supersaturated with respect to iron

carbonate, i.e. they are in the so called grey zone.

Effect of Organic Acids on CO2 Corrosion [21]

In the majority of the published work related to organic acid corrosion of mild

steel, the focus is on acetic acid due to its prevalence in a typical organic acid

mix seen in the field. In this work, the electrochemical behaviour of X65 carbon

steel in the presence of other important organic acids (formic and propionic)

and the effect that these have in the growth and protectiveness of iron

carbonate (FeCO3) scale have been investigated. It was found that very little

difference exists in electrochemical behaviour of the formic, acetic and

propionic acids when it comes to CO2 corrosion of mild steel, given that the pH

and concentrations of the undissociated organic acids is the same. Just like the

other two weak organic acids, formic acid increases the corrosion rate due to an

additional cathodic reaction: direct reduction of undissociated formic acid; this

reaction is very temperature sensitive and may be limited by diffusion. The

presence of organic acids makes it harder for protective iron carbonate scales to

form due to a scale undermining effect. The scale precipitation rate is not

directly affected, however, the time it takes to reach low corrosion rates is.

Labels: Chloride Stress Corrosion Cracking[22], CO2 [23], Corrosion [24]
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1. http://webwormcpt.blogspot.com/2008/10/co2-corrosion-in-oil-gas-part-2.html



4. http://webwormcpt.blogspot.com/2008/07/tips-on-succession-in-free-subscription.html

5. http://webwormcpt.tradepub.com/free/wup/prgm.cgi

6. http://www.corrosioncenter.ohiou.edu/documents/05554.pdf







13. http://webwormcpt.blogspot.com/2008/07/tips-on-succession-in-free-subscription.html

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23. http://webwormcpt.blogspot.com/search/label/CO2

24. http://webwormcpt.blogspot.com/search/label/Corrosion


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CO2 Corrosion in Oil - Part 2

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