CO2 Corrosion in Oil & Gas - Part 2

Display problem ? Click HERE

This is a continuation post from "CO₂ Corrosion in Oil & Gas - Part 1" on the useful article related to CO₂ corrosion in Oil & Gas.

Recommended :
- Tips on Succession in FREE Subscription
- Subscribe FREE - OilField magazine

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

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 the associated brine. This study evaluates the usefulness of Artificial Neural Networks (ANN) to predict the corrosion inhibition offered by crude 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 validity of 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

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 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

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

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 60°C) and high values of pH. An interesting 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 = 80°C has been studied under stagnant 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

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

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. At high 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-Phase Flow

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.

Recommended :
- Tips on Succession in FREE Subscription
- Subscribe FREE - Upstream magazine

CO₂ Corrosion of Carbon Steel in High Ionic Strength Brine Solution

The general CO₂ corrosion rates of C1018 carbon steel have been measured for NaCl concentrations 3 – 25 wt% at 5ºC, 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 CO₂ Corrosion

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 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 demonstrated that 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

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

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 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 by mechanical 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 demonstrated that 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

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.

To be continue...

Related Post

• CO₂ Corrosion in Oil & Gas - Part 1
• What are the concerns related to H₂S ?
• Several Concerns in High CO₂ Field Development
• How does Supercritical fluid looks like ?
• High Temperature Hydrogen Attack in metal & alloy
• Hydrogen Embrittlement TEST method
  
• Chlorride stress corrosion cracking and use of correct MOC for seawater