Iron Carbonate Scale Research Articles

Interaction between iron oxides and iron carbonates during running-in of C-steel tubings in CO2 corrosive environment

The present study investigates the running-in behaviour of low alloyed C-steel tubings in NaCl brine under CO2 corrosive environment. These corrosion conditions are those typically found in the oil industry. The corrosion of C-steel in CO2 environment leads to the formation of an iron carbonate scale. This scale determines the frictional behaviour at the interface between tubing and coupling. However, the tubing surface can contain iron oxides, either as a consequence of the production process or due to the presence of O2 in the environment. The role of iron oxides is addressed by investigating the running-in behaviour of tubings with and without oxide scale present, while the influence of iron carbonates is addressed by performing additional tests in distilled water under N2 environment. The results show that the interaction between iron oxides and carbonates determines the running-in behaviour of the tubings. The presence of iron oxides impairs the lubricious properties of the iron carbonate scale. This causes an increase in shear stresses at the sliding interface, as evidenced by the severe plastic deformation of the substrate. As a consequence, the presence of iron oxides during running-in leads to a transition from mild to severe wear.

Investigation on the efficiency of corrosion inhibitor in CO2 corrosion of carbon steel in the presence of iron carbonate scale

In this work, the inhibition efficiency of an imidazoline derivative corrosion inhibitors in CO2 corrosion of carbon steel was investigated in the presence of iron carbonate scale and hydrogen sulfide. The use of corrosion inhibitors is one of the most common controlling techniques for CO2 corrosion of carbon steel in oil and gas industry. One of the imidazoline derivatives was used as a corrosion inhibitor which protects the surface through the film formation mechanism. The investigation material was API 5L X65 carbon steel which was cut from a wet gas transmission pipeline. The internal surface of the pipe was covered with iron carbonate as corrosion product. In order to investigate the inhibitor efficiency, Tafel polarization and electrochemical impedance spectroscopy were done in CO2-saturated 3.5 wt.% sodium chloride solution. According to the results, the existence of iron carbonate film reduced the inhibition efficiency. Furthermore, it was found that in the presence of H2S gas, the inhibition efficiency was decreased due to the decrease in inhibitor adsorption on the surface.

Failure analysis of a wet gas pipeline due to localised CO 2 corrosion

Abstract CO2 corrosion is one of the main causes of failures of pipelines transporting wet gas. It can happen in general and localised form. In this study, the impact of the presence of iron carbonate scale which formed during process on CO2 corrosion behaviour of API 5L X65 carbon steel has been investigated by electrochemical measurements. The chemical composition and morphology of the scale has been studied via X-ray diffraction and scanning electron microscope. The scales were found to be iron carbonate scale with trace amount of iron sulphide. The result of electrochemical analysis revealed that the uniform corrosion rate of carbon steel decreases in the presence of iron carbonate scale. Furthermore, the bare and continuously covered sample with iron carbonated did not show susceptibility to localised CO2 corrosion. However, the presence of uneven iron carbonate scale or formation of thin, porous or defected scale can result in a potential difference between this area and adjacent area covered with compact scale followed by localised corrosion.

Study on the Effect of Surface Finish on Corrosion of Carbon Steel in CO2 Environment Revisited

To study the effect of surface finish is important to predict corrosion rate that happen in the as-delivered internal pipe surface. In between the very few systematic studies of this effect on carbon steel under carbonic acid attack, it was concluded CO2 corrosion increased with increasing surface roughness. Nevertheless, previous studies has probe onto mild corrosion conditions (room temperature, one atmosphere of pressure). Given that the formation of a tenacious iron carbonate scale can protect the surface, it is important to perform these studies at harder conditions. In this paper, we present evidence that corrosion rate can do the opposite, it can increase as the surface roughness decrease. This, however, occurs for the same reason. A rougher surface can react faster and therefore, produce a protective iron carbonate layer.

Prediction of Iron Carbonate Scale Formation in Iranian Oilfields at Different Mixing Ratio of Injection Water with Formation Water

Enhanced oil recovery methods are used to recover the percents of oil that are not naturally recoverable from reservoirs. Water injection, as a secondary recovery, is used to maintain the pressure in water-driven reservoirs. An important point for having a successful injection is the compatibility of injection and formation waters. This article presents the predicting scale tendency and scale precipitation of iron carbonate at different mixing ratios of injection water with formation water in Iranian oilfields. The experimentally measured chemical analyses of formation water and injection water were used by OLI ScaleChem software to determine the formation of this scale. This software has been applied to investigate the potential of iron carbonate scale formation in Iranian oilfields, as a method of secondary recovery or reservoir pressure maintenance.

A New Approach for Predicting Inhibited Erosion-Corrosion in CO2-Saturated Oil/Brine Flow Condition

Summary Chemical inhibition is a common method for controlling erosion-corrosion in offshore mild steel pipelines, tubing and pipe fittings. This paper introduces a new approach for predicting inhibited erosion-corrosion in mild steel pipes, including the effects of flow and environmental conditions, sand production, and an oil phase. When sand is produced, sand particle impingement on piping surfaces can decrease the efficiency of corrosion protection systems, such as iron-carbonate scale formation or chemical inhibition, and can result in severe corrosion and even pitting. The need to be able to predict inhibitor performance under sand-production conditions is particularly acute when the wells are deep or offshore because of the difficulty in running coupon tests to evaluate the inhibitor efficiency at critical points throughout a system. The research reported in this paper is aimed at providing producers with information that will help them make decisions on the design of the well given advanced knowledge of the inhibition options and their predicted effectiveness under sand-production conditions. Inhibition mechanisms and the relation between inhibitor concentration and inhibitor coverage are described using adsorption isotherms. The Frumkin isotherm showed the best fit to experimental data for an imidazoline-based inhibitor used in sand-free conditions. Flow-loop tests indicated that sand particle erosion decreased the efficiency of the inhibitor. However, Frumkin isotherms modified to handle effects of erosivity, temperature, and oil phase were successfully fitted to erosion-corrosion data. Inhibitor adsorption isotherms, for both sand-free and sand-production conditions, were integrated into a mechanistic model for prediction of CO2 corrosion rates as a function of inhibitor concentration, and good results were obtained when compared with data. Results of this study show that the inhibitor adsorption isotherm, modified to handle effects of sand production, temperature, and oil phase, can be a valuable tool for predicting inhibited metal loss rates under sand-production conditions.

Experimental Study on the Effect of the Water-Cut Conditions on the Performance of L80 Carbon Steel

In the oil production, water and acidic gases, i.e., H2S and CO2, are co-produced with the oil. The acidic gases are known to associate with a variety of corrosion damage to the surface facilities leading to costly failures. Also, the acidic gases cause a reduction in the service life of equipment. Corrosion of API L80 tubular carbon steel in sweet media (in the presence of CO2 gas) was investigated using the linear polarization resistance meter. Experiments using API L80 tubular carbon steel material were carried out in a stagnant flow condition with different ratios of produced water to crude oil at relatively high temperatures (60 °C up to 90 °C). The pressure was about 200 psi (13.8 bar) of CO2, and the experiments were carried out using a high pressure vessel namely an autoclave cell. Under those experimental conditions, results indicated that at a temperature of 60 °C, the corrosion rate for carbon steel L80 increased as water-cut ratio increased. Also, the results showed that at higher temperature than 60 °C, the formation of iron carbonate scale on the surface of the steel was observed to increase. Consequently, the corrosion rate of the L80 carbon steel was observed to decrease.

Flow Loop Study of NaCl Concentration Effect on Erosion, Corrosion, and Erosion-Corrosion of Carbon Steel in CO2-Saturated Systems

Abstract Erosion-corrosion deterioration of carbon steel in carbon dioxide (CO2)-saturated systems with sand is a problem in the oil and gas industry because the combined effects of erosion and corrosion can reduce the protection provided by iron-carbonate scale formation or inhibitors. Oil and gas production can be accompanied by the formation water (typically chloride containing brine). Some effects of chloride concentration on corrosion are not widely known, and this can result in misleading conclusions. The goal of this paper was to contribute to a better understanding of the effects of chloride concentration in CO2 corrosion. Previous studies reported in the literature and experimental and theoretical studies conducted in the present work have shown that increasing the sodium chloride (NaCl) concentration in solution has three important effects on corrosion results. First, standard pH meter readings in high NaCl concentration solutions require corrections. Second, increasing the NaCl concentration de...

Localized CO2 corrosion propagation at moderate FeCO3 supersaturation initiated by mechanical removal of corrosion scale

The propagation of localized CO2 corrosion was investigated at moderate iron carbonate supersaturation using an artificial defect method with re-formed corrosion scale. A mechanical tool was developed which locally removed pre-formed iron carbonate scale and initiated localized corrosion at a FeCO3 supersaturation of 3–10. The localized corrosion rate was calculated based on electrochemical measurement using a simplified algorithm and was also measured at the deepest part of the defect using scanning electron microscopy. Localized corrosion was driven by a galvanic cell established between the two surfaces exposed in the artificial defect where an open circuit potential difference was maintained.

Spontaneous passivation observations during scale formation on mild steel in CO 2 brines

Previous study revealed localized corrosion in CO 2 environments was driven by a galvanic cell established between pit surfaces and scaled surrounding area. In order to underpin the understanding of the galvanic mechanism of localized corrosion, the root cause of potential differences between these two surfaces, passivation of mild steel, in CO 2 environments was investigated using transmission electron microscopy technique and electrochemical techniques including potentiodynamic polarization, cyclic polarization and open circuit potential techniques. Potentiodynamic polarization experiments showed that the passivation of the carbon steel surface favorably occurred at pH > 7 and facilitated with the presence of FeCO 3 scale. Cyclic polarization tests showed that polarization rate had an important influence on passivation behavior. At a slower polarization rate, lower passivation potential and current density were observed. Spontaneous passivation was evidenced by a significant increase of corrosion resistance and an open circuit potential without any externally applied current or potential during electrode immersion. This process is affected by pH, temperature, presence of CO 2 and iron carbonate. Nevertheless, iron carbonate film is not the only one responsible for passivation, as demonstrated from depassivation tests where passivity was lost without losing the existing iron carbonate film. Transmission electron microscopy technique was used to determine the structure of the passive layer. An extra phase, most likely magnetite, was observed to be beneath the iron carbonate scale and at the crystal grain boundaries which passivated the mild steel.

Chemistry and Structure of the Passive Film on Mild Steel in CO2 Corrosion Environments

The passivation process was carried out and monitored employing a three electrode electrochemical glass cell. Surface analysis using grazing incidence X-ray diffraction (GIXRD) elucidated that trace magnetite in the dominant siderite (FeCO3) was responsible for the passivation. Transmission electron microscopy (TEM) with the energy dispersive X-ray fluorescence (EDX) technique was used to determine the structure of the passive layer and confirm its chemistry. A passive phase tens of nanometers thick was observed beneath iron carbonate scale and at the crystal boundaries. Scanning transmission electron microscopy (STEM)/EDX profiles suggest that this phase is not a carbonate containing compound since only oxygen and iron were observed. This indicates that the possible chemical compound for the passive phase is an iron oxide, agreeing with the previous GIXRD surface analysis. Fe3O4 as a passive film was confirmed.

Mechanism of protective film formation during CO 2 corrosion of X65 pipeline steel

Electrochemical techniques, X-ray diffraction (XRD), and scanning electron microscopy (SEM) were applied to study the corrosion behaviors of X65 steel in static solution with carbon dioxide (CO 2) at 65°C. The results show that iron carbonate (FeCO 3) deposits on the steel surface as a corrosion product scale. This iron carbonate scale acts as a barrier to CO 2 corrosion, and can reduce the general corrosion rate. The protection ability of the scale is closely related to the scale morphological characteristics.

The Mechanism of Inhibitor - Scale Interaction in Carbon Dioxide Corrosion of Mild Steel

Investigations were conducted on the interaction between a corrosion inhibition and the precipitating iron carbonate scale, and their effects on the corrosion rate. Both the effects of iron carbonate precipitation on inhibited and uninhibited surfaces and the effects of inhibition on surfaces with iron carbonate scale were studied using electrochemical techniques. Generic imidazoline based inhibitors were added at various points in the iron carbonate scale formation process. The specimens were later analyzed using scanning electron microscopy (SEM). Although no antagonism was found under any condition tested, it was observed that the addition of the inhibitor hindered the corrosion rate, as well as retarded the growth of the iron carbonate scale due to the lower concentration of ferrous ion on the steel surface.

Carbon Dioxide Corrosion in Wet Gas Annular Flow at Elevated Temperature

Abstract Wet gas corrosion rates of plain carbon steel at the top and bottom of a high-pressure, 10-cm-diameter, horizontal pipeline were measured under annular flow conditions at 0.45 MPa carbon dioxide (CO2) and 90°C. The corrosive medium consisted of deionized water and a low viscosity hydrocarbon phase at water cuts of 80%. Superficial gas velocities (Vsg) of 15 m/s and 20 m/s were applied at a superficial liquid velocity (Vsl) of 0.05 m/s for 100 h. The corrosion rates measured by electrical resistance (ER) technique advanced in three stages, showing an exponential decay corresponding to the iron carbonate (FeCO3) scale forming process. The general corrosion rates measured by ER were low, which were also confirmed by the coupon weight-loss measurements of average corrosion rates. No flow-induced localized corrosion (FILC) was found for the flow and corrosion conditions applied. Surface analysis techniques such as scanning electron microscopy (SEM) and x-ray photoelectron spectroscopy (XPS) revealed t...

Prediction of Erosion-Corrosion Penetration Rate in a Carbon Dioxide Environment with Sand

Abstract In oil and gas wells producing carbon dioxide (CO2) with saturated water, carbon steel piping can corrode rapidly depending upon the nature of the hydrocarbon phases produced and on flow and environmental parameters. In some CO2 environments, a protective iron carbonate (FeCO3) scale can form on carbon steel piping walls and reduce corrosion rates to within acceptable design limits. If sand also is being produced, protective scales can be removed or prevented from forming on piping walls at points where sand particles entrained in the flow stream impinge the walls. When this happens, bare metal corrosion is enabled at these impingement points, and corrosion rates again reach high levels. This process involves both erosion and corrosion mechanisms and often is referred to as “erosion-corrosion.” In some cases, pitting occurs at impingement points, resulting in extremely high penetration rates. In the present work, a laboratory flow loop circulating a CO2-saturated sodium chloride (NaCl) solution a...

Chromatographic and iron carbonate dissolution methods for evaluating active ingredients in corrosion inhibitors

Three new methods for inhibitor evaluation are described. The first method utilizes measurements of the dissolution rate of iron(II) carbonate in the presence of the inhibitor. The remaining two methods rely upon measurements of gas and liquid chromatographic retention times on columns that are packed with iron(II) carbonate. All three methods assume that an iron carbonate scale protects the underlying metal from corrosion. The methods were tested by using linear amines as test inhibitors and by comparing the results to weight loss measurements. Although the methods do provide adequate results for pure amines, the use of commercial inhibitor mixtures with the chromatographic methods sometimes proved unsatisfactory.