Application of Turbulence Models for Calculating the Erosion-Corrosion Rate in N80 Steel with CrSiN Coating

A technique proposed to control corrosion of the drill pipe is removal of oxygen from the drilling fluid. One approach to oxygen reduction is to substitute an anaerobic gas for air in the drilling fluid. A critical question to be answered when designing the anaerobic gas generator is what level of oxygen concentration is acceptable within the inert gas such that a low corrosion rate will be maintained. A laboratory program was done to answer this question. The program was designed to determine the effect of oxygen content, salt concentration and pH level on the corrosion rate of plain carbon steel. The corrosion rate of steel was found to decrease with increasing salt concentration at fixed pH levels and with oxygen contents in solution at equilibrium with air at 90/sup 0/C. The corrosion rate was found to decrease with increasing pH at fixed concentrations of salt and oxygen at 90/sup 0/C. The corrosion rate was also found to be proportional to the dissolved oxygen concentration at fixed pH levels and salt concentration. It is recommended that the anaerobic gas generator be designed to lower the oxygen concentration one order of magnitude below that in solution in equilibrium with air, that is, to approximately 500 ppB at 90/sup 0/C.

Infrastructure development in the United Arab Emirates continues to escalate, yet very few corrosion studies have been performed in the region. In a step to address this situation, this paper reports on a study of zinc and steel corrosion and salt deposition rates at five sites in the Emirate of Abu Dhabi. The sites are classified as either urban/marine, marine, inland or mountainous. The study found that zinc corrosion rates range from 15 µm/year on the coast to 0.6 µm/year inland, while steel corrosion rates are 56 and 10 µm/year, respectively, at the same locations. While the salt deposition rate ranges from 5 to 18 mg/m2/day, it is not directly related to distance from the coast. Although the salt deposition rates observed are consistent with those at locations at similar latitudes, the corrosion rates are higher than in locations with comparable salt deposition rates. However, when the data were analysed along with relevant local meteorological data, it was found to be consistent with the basic assumptions of the holistic model of atmospheric corrosion developed byColeet al. In particular, it is suggested that the relatively high corrosion rates observed here are associated with a greater accumulation of salt, which can occur in Abu Dhabi because rainfall, and thus rain washing, is extremely low compared to similar exposure locations in Australia and South‐East Asia.

In the process of oil and gas extraction, N80 steel is used as a common tubing material. CO2 corrosion has become one of the most dangerous problems in its entire life cycle. In this paper, the conditions of different temperatures (90-220 °C) and CO2 partial pressure (0.2-3 MPa) were selected, and the dynamic rotating high-temperature autoclave was used to simulate N80 steel corrosion in formation water environments. The results showed that the corrosion rate of N80 steel gradually decreased with the increase of temperature, and the corrosion rate was the lowest at 150 °C. In addition to this, with the increase of CO2 partial pressure, the corrosion rate first increased and then decreased. The corrosion rate was the highest when the CO2 partial pressure was 0.8 MPa. Through surface analysis techniques (SEM and XRD) and electrochemical tests, it was found that the corrosion resistance of N80 under high temperature and high pressure is closely related to the corrosion product film (FeCO3). The compactness of FeCO3 product film determines the corrosion characteristics of the matrix.

In this study, the corrosion behavior of N80 and TP125V steels was delved firstly into produced water from shale gas fields containing CO2-O2. Moreover, the localized corrosion of these steels was investigated to elucidate the effects of aerobic and anoxic on steel corrosion. The results indicated that the corrosion rates of N80 and TP125V steels under aerobic conditions were lower compared to those in the presence of CO2-O2. Specifically, at temperature of 100 °C and with dissolved oxygen (DO) concentration of 4 mg/L in the CO2-O2 environment, the N80 and TP125V steels exhibited the highest corrosion rate, with values of 0.13 mm/y and 0.16 mm/y, respectively, as determined by specific weight loss measurements. Conversely, these rates decreased to 0.022 mm/y and 0.049 mm/y under aerobic conditions. Furthermore, severe localized corrosion of N80 and TP125V steels with a DO concentration of 4 mg/L was also observed in the CO2-O2 environment. Finally, it was evident that pitting corrosion is the predominant type of corrosion affecting N80 and TP125V steels in the produced water from shale gas fields.

Marine oil pipelines are critical for the transportation of oil and gas from offshore production facilities to onshore processing plants. However, exposure to seawater, salt, and other environmental factors can cause corrosion in these pipelines, which can lead to costly and dangerous leaks and spills. Therefore, predicting and managing corrosion in marine oil pipelines is essential for ensuring safe and efficient operation. Uniform/general corrosion, pitting corrosion, and microbiologically influenced corrosion (MIC) are the most common forms of corrosion found in marine oil pipelines. These corrosion mechanisms can lead to thinning of the pipe walls and the formation of pits, which can significantly weaken the structure of the pipeline. To detect and monitor corrosion in marine oil pipelines, various in-line inspection (ILI) tools are available. Some of the most commonly used ILI tools for marine pipelines include magnetic flux leakage (MFL)[1], ultrasonic thickness measurement (UTM), and eddy current inspection (ECI). However, the existing tools are not efficient because of low accuracy. Therefore, a corrosion rate model was developed for the future rate of corrosion in marine oil pipelines. The developed model accounts for various factors such as line diameter, line temperature, line pressure, CO2 concentration, H2S concentration, Volatile fatty acid concentration, Bacteria count(SRBs), Material of construction, service life, bicarbonate ion concentration, chloride ion concentration, sulphate ion concentration, pH, clamp/repair history and details, oil, water and gas flow rate, flow velocity and regime, Inhibitor/biocide frequency, Oil characteristics and Kinetics of reaction to estimate the expected corrosion rate over a given time period [2]. Also the developed model combines the both linear corrosion growth rate, and non-linear corrosion growth rate. The model was trained on historical data of corrosion rates for different conditions and validated on new data to ensure accuracy. Additionally, the model could be updated in real-time with sensor data from the pipeline, allowing for continuous monitoring and prediction of corrosion rates. This could help operators proactively manage and maintain the pipeline to prevent corrosion-related failures and minimize downtime. A validation study was conducted on the developed model using a dataset of real-world pipeline corrosion data. The model was trained on a subset of the data and tested on a separate subset. The results showed a high level of accuracy, with an overall accuracy of 96%. This level of accuracy suggests that the model is reliable and can be used to inform pipeline integrity management and planning with a high degree of confidence.

Electrochemical noise analysis for estimation of corrosion rate of carbon steel in bicarbonate solution

It is important to monitor the corrosion rates of steel in electrolyte environments such as aqueous solution or soil in order to evaluate the integrity of the members of facilities. As the nondestructive monitoring method, polarization resistance (Rp) method is generally known. The corrosion rate icor is calculated by the equation of icor=k/Rp. Herein k is a constant decided on the specific condition of steel surface and the environment. It is not easy to decide k on each condition. As a monitoring method without deciding k has been demanded, CIPE (Current Interrupted Polarizing Extrapolation) method was developed. By CIPE method the corrosion rate is calculated by the Tafel equation obtained from the polarization curve of in situ measurement. In this paper, in order to confirm accuracy of the method, the measured corrosion rates of carbon steel were compared with the values calculated from mass losses of steel specimens in neutral aqueous solution. As a result, the mass losses calculated form corrosion rates by CIPE method indicated the similar values of the actual corrosion mass losses. Therefore it is clear that CIPE is a useful method for real time monitoring of corrosion rate of steel in aqueous solution.

There have been several instances where water purified from seawater by reverse osmosis has caused accelerated corrosion of carbon steel pipes. Therefore research was undertaken to determine the corrosion rate of low carbon steel in water with different contaminants, with and without aeration, and at different velocities. The results show that in high purity deionized (DI) water with oxygen, the corrosion rates were initially very high but dropped rapidly within a few hours to <100μm/yr. In jet impingement of DI water with oxygen, the corrosion rates dropped even lower, approaching zero, because the steel surface passivated. Water analysis from the reverse osmosis units from the offshore oil drilling platforms showed that reverse osmosis units would typically leave behind many ppm of NaCl and Na2SO4. Therefore laboratory tests were conducted and it was found that adding NaCl and Na2SO4 to the DI water, increased the corrosion rate, proportionally to the concentration. In the jet impingement tests with contaminated water containing oxygen, the corrosion rate of the steel was ~5 mm/yr, beneath a thick, gelatinous, ferric hydroxide film. When the same jet impingement tests were conducted with high purity DI water saturated with oxygen, the corrosion rate was zero, due to the steel surface passivating.

The purpose of this research is to investigate the corrosion rate of carbon steel as flowline and pipeline in natural gas production with CO2 content. The influence of variety of conditions that represent the actual conditions in practice such as CO2 partial pressure and solution composition, particularly NaCl percentage were performed. Research conducted by polarization test and simulation methods using PREDICT TM software. The result of this research is used to illustrate the level of corrosion rate of typical carbon steel i.e. API 5L X-52 occurred in natural gas pipelines due to the effect of dissolved CO2. From the experiments obtained that corrosion rate of steel in environments containing CO2 ranged between 15-28 mpy. This high corrosion rate observed could severely damage natural gas transmission flowline and pipeline. The result of this research is the first step, as an input for prevention efforts, to prevent leakage of flowline and pipeline due to corrosion of CO2 which appropriate with the lifetime that has been designed.

At present, the transportation environment of heavy oil pipelines is complex and subject to a specific set of factors. However, external corrosion problems are inevitable. In this work, the corrosion rate, corrosion morphology and corrosion products of 16Mn heavy oil pipeline steel in the reed pond soil of the Liaohe oilfield were studied by immersion experiments and SEM, EDS and XRD analysis methods. Based on the gray correlation analysis method, the effect of five factors influencing the corrosion rate of 16Mn steel in a reed pond soil environment was discussed by utilizing dynamic potential polarization and AC impedance technology. The analysis of potential dynamic polarization and AC impedance technology shows that the corrosion rate gradually increases due to the decrease in pH and the increase in temperature and concentration of the corrosive anions Cl−, SO42− and HCO3− in the environment. The order of the correlation between influencing corrosion factors and the corrosion rate of 16Mn steel is as follows: temperature > Cl− > SO42− > HCO3− > pH value.

RETRACTED: The experimental and innovative research on usability of sulphur polymer composite for corrosion protection of reinforcing steel and concrete

From September 1992 to September 1995, the corrosion behavior of three marine steels was studied in Chengdao offshore area by means of individually and electro‐connectedly hanging plates in order to provide data for anticorrosion design of oil‐exploitation structures there.The variation trend of corrosion rate with exposure time showed that the variation curves and degrees of three steels were generally identical and had nothing to do with the exposure time. The whole change trend of corrosion rates in three years showed that the corrosion rates of 20# steel were nearly identical in different positions, each of which was a little lower than that of 16 Mn steel specimens in corresponding positions, also was lower than that of A3 steel specimens in tidal zone and immersion zone. Although 20# steel corroded rapidly at first, its corrosion rate has a decreasing trend in the long‐term service. Therefore, 20# steel is feasible to be applied for a long time in various marine zones, especially nearby the low tidal line and immersion zone. The results of A3 steel, 16 Mn steel and 20# steel by means of electrically connected hanging plate in three years indicated that the corrosion of the steel specimens in the splash zone was the most severe as the result of dry‐wet cycle and macrocell effect. Specimens in the other positions corroded mildly, and that in tidal zone corroded most slowly. The corrosion rate of 20# steel was the highest among the three steels in the test, and the corrosion rates of A3 steel and 16 Mn steel were identical on the whole. When the specimens were hanged electro‐connectedly, the macrocell effect generally tended to increase with exposure time. The highest corrosion rate of A3 steel in the splash zone in the three years was about 0.278 mm/a, while that of 16 Mn steel was about 0.321 mm/a, and that of 20# steel was 0.330 mm/a or so. In contrast, the corrosion rate of the steels in the tidal zone was the lowest in three years, which were 0.052 mm/a (A3 steel), 0.048 mm/a (16 Mn steel) and 0.040 mm/a (20# steel).

This paper presents the results of the experimental research and analyses indicating the usefulness of polymer sulphur composites to the protection against corrosion of reinforcement. In paper presents materials also the domain of the personal investigations and the methodology are definite. After the analyze of the initial results the optimum compositions have been chosen to the experimental research. This paper presents investigation results of corrosion rate for steel reinforcement bars that have been covered with polymer coating and have been exposed to tensile stresses in a solution simulating pore-liquid of concrete. Experimental investigation of tendencies that occur during corrosion process of reinforcing steel covered with polymer and exposed to tensile stress has been attempted. To determine an effect of tensile stress on corrosion rate for St3S-b steel that has been covered with sulphuric coating and exposed to aqueous environment that was to simulate pore-liquid of concrete contaminated with chloride ions was an aim of the investigation. The samples underwent loading in an one-axial state of the stress including varied values of tensile stress, at the same time corrosion rate was determined potentiostaticaly. Potentiostatic investigation has been carried out in order to determine parameters describing corrosion rate of samples tested. Corrosion rate for the steel has decreased by orders of magnitude when covered with protective coating even though this latest became unseal at load exceeding. A small decrease of corrosion rate has been found for the steel that has not been covered with polymer coating when placed in model pore-liquid of concrete and exposed to tensile stress increasing. http://dx.doi.org/10.5755/j01.u.66.2.531

An electrochemical impedance study on atmospheric corrosion of steels in a cyclic wet-dry condition

The corrosion rate of carbon steel in 50 to 99% sulfuric acid is controlled by the rate at which the ferrous sulfate corrosion product diffuses. The rate at which ferrous sulfate diffuses in sulfuric acid and therefore, the corrosion rate of steel has been calculated for pipeline flow. The final expression for the corrosion rate in mm/yr of carbon steel pipelines is CR = 1.42 x 10-4 T0.654 γ0.913 ρ1.567 μ-1.221 d-0.087 (w - 0.01). Corrosion rates calculated from this expression are in agreement with reported corrosion rates from the literature.