CO2 Corrosion Rate Research Articles

Corrosion inhibition properties of sweet crude oil for carbon steel 1018 in NaCl solution

Abstract Aged oil pipeline production systems, historically designed without corrosion protection due to predominantly oil-wetted conditions, now face significant changes as increased water content in produced oil arises from field maturation. This work investigates the corrosion inhibition properties of sweet crude oil on carbon steel 1018 in a CO2-saturated NaCl solution using electrochemical testing (open circuit potential, polarization resistance, electrochemical impedance, potentiodynamic polarization) and surface characterization (SEM, EDS) techniques at 50 °C and pH 6. Carbon steel specimens were immersed in crude oil for durations ranging from 0 to 144 h before undergoing corrosion testing. Results showed that a 144-h immersion in crude oil led to an 88 % reduction in corrosion rate, comparable to the efficiency of standard quaternary ammonium-based inhibitors. Furthermore, a semi-empirical model predicting uniform CO2 corrosion rates for varying oil immersion durations is proposed and validated by comparing its predictions with experimental data from the electrochemical tests.

Computational fluid dynamics driven mass transfer model for the prediction of [formula omitted] corrosion in pipelines

A novel, computational fluid dynamics (CFD) driven modelling methodology for predicting CO2 corrosion rates in pipelines is presented. CFD is used to provide accurate predictions of the viscous sublayer thickness and turbulent diffusivities, which are then used within a mass transfer model of aqueous CO2 corrosion. Comparisons with experimental measurements of corrosion rate in horizontal pipe flow and corresponding theoretical predictions, based on empirical correlations and previous CFD approaches, show the new approach is more accurate for flows in the range of pH 4 to 6. However, the key advantage of the new approach is its flexibility. Existing models are inaccurate and highly restrictive, having been derived for very simple cases, such as 1 D pipe flow. In contrast, the new methodology provides a firm, scientific foundation for predicting corrosion rates by determining conditions in the viscous sublayer in much more complex, and practically relevant, flow situations.

Effect of Surface Roughness on Static Corrosion Behavior of J55 Carbon Steel in CO2-Containing Geothermal Water at 65 °C

The influence of surface roughness on the static corrosion behavior of J55 carbon steel in CO2-containing geothermal water environment was investigated with respect to average corrosion rate, morphology, chemical composition, corrosion depth, and the cross section of corrosion products. The influence of surface roughness on the CO2 corrosion of J55 carbon steel was then proposed based on the understanding of corrosion at 65 °C. The results show that the static corrosion rate of J55 carbon steel in CO2-containing geothermal water increases with increasing surface roughness. The surface roughness of J55 carbon steel increases 5.3-fold and the CO2 corrosion rate increases by 1.4-fold under different exposure times. The static corrosion rate of J55 carbon steel in CO2-containing geothermal water changes with exposure time. The corrosion rate of J55 carbon steel decreases with the increase in exposure time, and there is little change in the corrosion rate after immersion for 2 days. At the initial stage of corrosion, the corrosion rate of J55 carbon steel was mainly affected by surface roughness. The greater the roughness, the greater the corrosion driving force and the corrosion reaction surface area and therefore the greater the corrosion rate of J55 carbon steel. After immersion for 2 days, a continuous corrosion product layer was formed on the surface of J55 carbon steel and the corrosion rate was mainly affected by the corrosion product layer. The corrosion products of J55 carbon steel are not altered by surface roughness in a CO2-containing geothermal water environment. The corrosion products of J55 carbon steel are FeCO3 and a minute amount of CaCO3.

Mathematical Modelling of CO2 corrosion with NORSOK M 506

The consequences of corrosion is catastrophic also costs reached the global economy “$2.5 trillion, or world GDP’s 3.4%”. Despite the magnitude of the corrosion cost, it can be concluded that scientific studies on corrosion prevention are quite limited, with the exception of high-risk sectors such as aviation and the fuel oil industry. It is important to fight against corrosion in order to ensure the safe operation of oil-carrying pipelines under the sea; and to prevent accidents and environmental damage. As a result of developing industry conditions and increasing needs, modelling corrosion is a very effective method in the prevention of corrosion. Industry, research companies and universities have developed many corrosion rates, prediction models. One of them is the NORSOK M 506 model. In this study, the NORSOK M 506 CO2 corrosion prediction model and the experimental results conducted by Nešić, Solvi and Enerhaug in 1995 were compared in terms of CO2 corrosion rate. The results showed that the mathematical corrosion model calculated nearly six times higher than the experimental study within conformity.

Effect of a Small Amount of Cr and Mo on Aqueous CO2 Corrosion of Low-Alloyed Steel and Formation of Protective FeCO3 in Near-Saturation Conditions

The effect of a small amount (1 wt%) of Cr or Mo on aqueous CO2 corrosion of low-alloyed steel and the formation of protective FeCO3 corrosion product layers was investigated under controlled water chemistry conditions, where the bulk saturation value of FeCO3 was maintained at near-saturated condition. Changes in CO2 corrosion rate with exposure time were monitored by linear polarization resisitance measurements. The surface morphology and the composition of the corrosion product layers were analyzed by scanning electron microscopy, energy dispersive x-ray spectroscopy, x-ray diffraction, and transmission electron microscopy. Results showed that the emergence of a continuous Fe3C layer created favorable conditions at the surface of nonalloyed steel (containing no Cr and Mo) for semiprotective FeCO3 to form even though the bulk saturation value of FeCO3 was maintained at near-saturated condition. However, semiprotective FeCO3 was not observed on the surface of 1% Cr steel and 1% Mo steel, but rather discontinuous and porous corrosion product layer was formed. Due to the hydrolysis reactions of Cr3+ and Mo3+, and the discontinuous structure of the corrosion product layers, the surface conditions for 1% Cr steel and 1% Mo steel were not favorable for the formation of FeCO3 under the experimental conditions of this study.

Influence of Temperature on CO₂ and H₂S Corrosion Rates of Steel Pipelines Using Alloy-Select Software in the Lebanese Oil and Gas Offshore Environment

By referring to the fact that corrosion rates alter upon variation of different conditions and no research relevant to Lebanon address corrosion issues yet, this study was conducted based on accurate Lebanese offshore data and water composition. Based on "Alloy Select Software", identifying the most suitable material from different alloys was revealed, which turned out to be Copper and Aluminum based alloys. Moreover, corrosion rates were detected under different conditions of Temperature, CO₂, and H₂S and then repeated in the presence of a corrosion inhibitor. Results of these studies proved the significant influence of high temperature accompanied with high CO₂ percentage. However, different results concerning low temperature with different percentages of H₂S were obtained.

Corrosion simulation via coupling computational fluid dynamics and NORSOK CO2 corrosion rate prediction model for an outlet header piping of an air-cooled heat exchanger

In this study CO2 corrosion of outlet header pipe of an air-cooled heat exchanger in a natural gas dehydration unit of a gas refinery was investigated by simulation via coupling computational fluid dynamics and NORSOK M-506 CO2 corrosion prediction model. The Euler-Euler approach incorporated with k–ε model for the fluid turbulence was employed to simulate gas-liquid two-phase flow. The simulation results were utilized as the inputs of NORSOK CO2 corrosion prediction model to calculate CO2 corrosion rate. Fluid streamlines, velocity, viscosity, density and temperature profiles and also the distribution of gas and liquid phases through the investigated outlet header pipe were calculated and a three-dimensional corrosion rate map was presented. The results showed that there is a good agreement between the data obtained by corrosion simulation and field observation. It was found here that coupling computational fluid dynamics and CO2 corrosion prediction models can successfully predict regional corrosion rates and determine locations susceptible to CO2 corrosion.

In situ mathematically simulation for CO2 internal corrosion in wet natural gas gathering pipelines system by HYSYS

The rate of corrosion due to the presence of carbon dioxide in a carbon steel pipe is an important design consideration for gathering pipelines, particularly in the transport of wet natural gas. To evaluate the corrosion rate in a gathering pipeline, in situ simulation study using HYSYS program employed to predict CO2 corrosion in natural gas gathering pipelines system. The effects of operational conditions, inhibitors, pipe parameters and flow regime on the CO2 corrosion are studied in this paper. Increasing operating pressure leads to increase the pH and decrease the CO2 corrosion rate when the operating pressure over 10 MPa and the solution contents 0.85kmol/m3 iron carbonate. The CO2 corrosion rate does not always increase with temperature, and which will reach a maximum value at 45 °C. A high gas velocity will lead to a high corrosion rate. Less free water present in pipeline may lead to more serious corrosion than that of a large amount of free water. The corrosion rate may be inhibited by liquid hydrocarbon and glycol, and the glycol is not an economic inhibitor, especially when there is a large amount of free water in pipeline. The large diameter and flat pipe are useful for decreasing CO2 corrosion rate. The shear stress and corrosion rate will increase sharply when the slug flow forms in pipeline. Through comparing the data of simulation with field corrosion rate data, feasibility of this numerical simulation method is proved.

Experimental Study on Corrosion of J55 Casing Steel and N80 Tubing Steel in High Pressure and High Temperature Solution Containing CO2 and NaCl

The downhole casing and tubing in thermal recovery wells are the main channels for fluid flow. The corrosion for casing and tubing in high pressure (5 MPa) and high temperature (200 °C) (HPHT) fluid can cause string failure due to wall thinning, deformation, and fracture. In order to study the corrosion characteristics of J55 casing steel and N80 tubing steel in HPHT environment containing CO2 and NaCl, corrosion and corrosion inhibition experiments were carried out using a rotating autoclave at a pressure of 5 MPa and 50–200 °C environment. Morphologies and compositions of corrosion products were analyzed by SEM and XRD. HPHT corrosion process was discussed by Arrhenius equation and the transition state equation. Results showed that the corrosion rates of the two materials increased with CO2 partial pressure while increased initially and then decreased with increasing temperature. In CO2–NaCl solution, the saturate NaCl decreased the CO2 corrosion rates at low temperature (inhibition) and increased CO2 corrosion rates at high temperature. Meanwhile, SEM results showed that the surfaces of CO2 corrosion became more dense and uniform at high temperature. The increase of NaCl leaded to pitting and high concentration NaCl solution causes granular products to appear on the CO2 corrosion surface. The carbon steel corrosion rate is mainly controlled by kinetic parameters of activation; the activation parameters were increased by the increase in temperature and NaCl concentration. Oil-soluble imidazoline acts as a good inhibitor for corrosion of J55 and N80 in this work.

A semi-empirical model for CO2 erosion-corrosion of carbon steel pipelines in wet gas-solid flow

The research of CO2 erosion-corrosion (E-C) of carbon steel pipelines in wet gas-solid flow, as a critical consideration for oil and gas engineering applications, is increasingly receiving more and more interest and attention. A semi-empirical model for the prediction and risk assessment of the conjoint CO2 E-C rate in such conditions is proposed. The variation of fluid properties with system environment is considered during gas-solid flow. The Eulerian-Lagrangian method is employed to solve the N–S equation for computational domain flow field and the force balance equation for migration trajectory of solid particles in the simulation space, and the fluid-solid interaction is considered. An empirical CO2 corrosion model as well as its modified form is provided and verified and an erosion wear model is also adopted, which are both suitable for carbon steel. In addition, the synergistic effect of both models is considered. Based on the above contents, the CFD-DPM technology with test data is adopted to obtain the parameters that are used in both models, and the total CO2 E-C rate, separate erosion rate, separate CO2 corrosion rate can then be obtained at different positions of the pipeline wall. Furthermore, the dominated rate is determined and analyzed, and based on the total CO2 E-C rate, the severity of the conjoint CO2 E-C is shaped. The proposed model can quickly and conveniently compute and determine the dominated rate and severity at different positions, and then further determine the weak positions and statuses where pipeline failures may happen. The model is expected to provide theoretical support for the prevention and daily risk management of carbon steel pipelines failures during the process of oil and gas production and transportation, so as to safely and reliably complete the established production tasks and maximize the economic benefits.

State-of-the-art of CO2 capture with amino acid salt solutions

Abstract The emission of large amounts of CO2 into the atmosphere is believed to be a major reason behind climate change, which has led to increased demand for CO2 capture. Postcombustion CO2 capture with chemical solvent is considered one of the most important technologies in order to reduce CO2 emission. Amino acid salt solutions have attracted special attention in recent years due to their excellent physicochemical properties, e.g., low volatility, less toxicity, and high oxidative stability, as well as capture performance comparable with conventional amines. In this study, physicochemical properties of 20 amino acids are reported and their CO2 absorption performance discussed. The topics covered in this review include the most relevant properties of amino acids including CO2 loading capacity, cyclic capacity, equilibrium constant, density, viscosity, dissociation constant, CO2 solubility, CO2 diffusivity, reaction kinetic between CO2 and amino acid salts, reaction rate constant, surface tension, heat of CO2 absorption, precipitation, toxicity, solvent degradation, and corrosion rate. This review provides the most recent information available in the literature on the potential of using amino acid salts as a solvent for CO2 capture which can help improve the performance of the CO2 capture process from flue gas streams.

Requirement and Calculation of Corrosion Allowance for Piping and Valves in the Oil and Gas Industry

“Acid Gases” refer to two of the undesirable by-products of oil and gas, namely CO2 and H2S$$.$$ The reaction of H2S and other sulphur compounds with water increases the degree of “sour corrosion” by forming sulphuric acid. CO2 corrosion of carbon and alloy steels is designated as “Sweet Corrosion” which is defined as the deterioration of metal components resulting from contact with gas or solutions including both CO2 and water. CO2 corrosion is an important problem in the oil and gas industry due to metal loss and its severe effects in terms of localized corrosion. Accurate prediction and modelling of CO2 corrosion rates for carbon and alloy steel pipes are vital tasks at the basic design phase of oil, gas and petrochemical projects in order to determine whether to consider additional wall thickness for the pipes and valves defined as “Corrosion Allowance (CA)” or to change the pipes’ or valves’ base materials to “Corrosion Resistance Alloys (CRA)”. Other corrosion mitigation approaches such as injecting the corrosion inhibitors and glycol or methanol can reduce the metal loss and CO2 corrosion. This paper proposes a practical model to calculate and select the corrosion allowance for piping and valves in oil and gas industry. Different process parameters such as scaling, fugacity, pH, glycol and corrosion inhibitor injection, water cut, operating pressure and temperature as well as CO2 partial pressure have been applied in the model.

Corrosion Control, Prevention and Mitigation in Oil & Gas Industry

The impact of corrosion within the refining industry ends up in the failure of components. This failure leads to closing down the plant to scrub the corroded components. Additionally, corrosion normally causes serious environmental issues, namely spills and releases. A vital resource for all those that are concerned within the corrosion management of oil and gas infrastructure, corrosion management within the oil and gas industry provides engineers and designers with the tools and strategies to plan and implement comprehensive corrosion-management programs for oil and gas infrastructures. Control of corrosion is important for continuous production and evading the well control losses. Materials to be used in down hole have to meet certain characteristics to avoid corrosion and provide additional mechanical strenght. It is potential to determine a logical series of steps for material choice, incorporating analysis of the surroundings, corrosion rate calculations, and final material choice based on established limits. Several developments have taken place in refinement the calculation of CO2 corrosion rates. Moreover, the definition of bitter examination has been reviewed and a way wider evaluation of the relevance of varied established and new materials for various service conditions has been created.

CO2 corrosion behavior of sensitized 304 and 316 austenitic stainless steels in 3.5 wt.% NaCl solution and presence of H2S

The CO2 corrosion behavior of sensitized and non-sensitized 304 and 316 stainless steels in the absence and presence of H2S was investigated using cyclic polarization and electrochemical impedance spectroscopy techniques. The sensitization resulted in significant negative shift on pitting potential for both alloys. The general CO2 corrosion rate of sensitized and non-sensitized samples was not significant. However, increasing H2S concentration up to 200 ppm resulted in severe increase in general corrosion rate and also significant negative shift for pitting potential. It was concluded that, the major role of sensitization is influencing the pitting potential and pitting corrosion of both alloys.

Corrosion behavior of X65 steel in CO2-saturated oil/water environment of gathering and transportation pipeline

Purpose The purpose of this paper is to investigate the corrosion behavior of X65 steel in the CO2-saturated oil/water environment using mass loss method, potentiodynamic polarization technique and characterization of the corroded surface techniques. Design/methodology/approach The weight loss analysis, electrochemical study and surface investigation were carried out on X65 steel that had been immersed in the CO2/oil/water corrosive medium to understand the corrosion behavior of gathering and transportation pipeline steel. The weight loss tests were carried out in a 3 L autoclave, and effects of water cut and temperature on the CO2 corrosion rate of X65 steel were studied. Electrochemical studies were carried out in a three-electrode electrochemical cell with the test temperature was 60°C, and the CO2 partial pressure was 1 atm by recording open circuit potential/time and potentiodynamic polarization characteristics. The surface and cross-sectional morphologies of corrosion product scales were characterized using scanning electron microscopy. The phases of corrosion product scales were investigated using x-ray diffraction. Findings The results showed that due to the wetting and adsorption of crude oil, the corrosion morphology of X65 steel changed under different water cuts. When the water cut of crude oil was 40-50 per cent, uniform corrosion occurred on the steel surface, accompanied by local pitting. While the water cut was 70-80 per cent, the resulting corrosion product scales were thick, loose and partial shedding caused platform corrosion. When the water cut was 90 per cent, the damaged area of platform corrosion was enlarged. Crude oil can hinder the corrosion scales from being dissolved by the corrosive medium, and change dimension and accumulation pattern of the crystal grain, thickness and structure of the corrosion scales. Under the corrosion inhibition effect of crude oil, the temperature sensitive point of X65 steel corrosion process moved to low temperature, appeared at about 50°C, lower corrosion rate interval was broadened and the corrosion resistance of X65 steel was enhanced. Originality/value The results can be helpful in selecting the applicable corrosion inhibitors and targeted anti-corrosion measures for CO2-saturated oil/water corrosive environment.

Failure analysis of carbon dioxide corrosion through wet natural gas gathering pipelines

The aggressive behavior of carbon dioxide dissolved in water considers as one of basic reasons behind corrosion failure in oil and gas processes. Simulation study using HYSYS program employed to predict CO2 corrosion in natural gas gathering pipelines system. This work examines the effect of operating pressure, temperature, pH solution, pipeline length, flow regime, and pipe inclination on the CO2 corrosion. Based on the simulation results, following highlights were identified: increasing operating pressure results in increases CO2 partial pressure and promotes corrosion rate. Temperature affects formation of protective layer, where maximum CO2 corrosion rate reached 2.96 mm/year at 40°C for this simulation conditions. After 40°C, the protective layer consists and becomes more dense and reduces corrosion rate. In addition, lower pH enhances the solubility of carbonate, reduces participation rate, and enhancing CO2 corrosion. Dissolved CO2 concentration decreases along the pipeline length and the corrosion rate reduces as result. High velocity means efficient mixing which leads to prevent the formation of the protective layer and increases CO2 corrosion. Pipeline inclination affects the velocity of flow where positive elevation change reduces fluid velocity, while minus elevation change promotes fluid velocity. Frequently, these factors depend on each other and sharing the effects on the CO2 corrosion. The prevention of CO2 corrosion in natural gas gathering pipelines starts by understanding the effects of the operation conditions.

Data-Driven Modeling of Carbon Dioxide Corrosion for Integrity Management Application

Summary In this work we expand on the carbon dioxide (CO2) corrosion–rate model presented by DeWaard et al. (1995) using a parameter–varying (PV) approach to improve prediction accuracy. Specifically, the constant coefficients of the reaction–kinetics–dependent term are replaced with varying parameters presented as a function of mean flow velocity and pH. On the basis of experimental data provided by Nešić et al. (1996) and Dugstad et al. (1994), we compare the corrosion–rate predictions between the original model and the proposed model. A significant improvement of the correlation coefficient (R2) from 0.54 to 0.90 is achieved when the PV coefficients replace the constant coefficients. Accurate predictions of the CO2 corrosion rate affect useful life forecasting of oil and gas systems during front-end engineering design studies, facilitate condition-based maintenance, and serve as the basis for the creation of a digital twin for this process.

The corrosion behavior of X65 steel in CO2/oil/water environment of gathering pipeline

Purpose The purpose of this paper was to investigate the corrosion behavior of X65 steel in the CO2/oil/water environment using mass loss method, potentiodynamic polarization technique and characterization of the corroded surface techniques. Design/methodology/approach The weight loss analysis, electrochemical study and surface investigation were carried out on X65 steel that had been immersed in the CO2/oil/water corrosive medium to understand the corrosion behavior of gathering pipeline steel. The weight loss tests were carried out in a 3L autoclave, and effects of flow velocity, CO2 partial pressure and water cut on the CO2 corrosion rate of X65 steel were studied. Electrochemical studies were carried out in a three-electrode electrochemical cell with the test temperature of 60°C and CO2 partial pressure of 1 atm by recording open circuit potential/time and potentiodynamic polarization characteristics. The surface and cross-sectional morphologies of corrosion product scales were characterized using scanning electron microscopy. The phases of corrosion product scales were investigated using X-ray diffraction. Findings The results showed that corrosion rates of X65 steel both increased at first and then decreased with the increase of flow velocity and CO2 partial pressure, and there were critical velocity and critical pressure in the simulated corrosive environment, below the critical value, the corrosion products formed on the steel surface were loose, porous and unstable, higher than the critical value, the corrosion product ?lms were dense, strong adhesion, and had a certain protective effect. Meanwhile, when the flow velocity exceeded the critical value, oil film could be adsorbed on the steel surface more evenly, corrosion reaction active points were reduced and the steel matrix was protected from being corroded and crude oil played a role of inhibitor, thus it influenced the corrosion rate. Above the critical CO2 partial pressure, the solubility of CO2 in crude oil increased, the viscosity of crude oil decreased and its fluidity became better, so that the probability of oil film adsorption increased, these factors led to the corrosion inhibition of X65 steel reinforced. The corrosion characteristics of gathering pipeline steel in the corrosive environment containing CO2 would change due to the presence of crude oil. Originality/value The results can be helpful in selecting the suitable corrosion inhibitors and targeted anti-corrosion measures for CO2/oil/water corrosive environment.

CO2 Corrosion Behavior of Calcite-Covered API 5L X52 Carbon Steel in Aqueous Solutions

The CO2 corrosion of API 5L X52 steel in the presence and absence of calcite scale has been investigated. The scale was precipitated from a supersaturated solution at temperatures of 25 and 80 °C. The crystalline phase, cross section and surface morphologies of scale were studied by x-ray diffraction and scanning electron microscopy, respectively. It was found that the scale deposit mostly consisted of calcite. The corrosion behavior of bare and calcite-covered samples was investigated by electrochemical impedance spectroscopy and cyclic polarization techniques in aqueous CO2 solutions at 30, 50 and 70 °C. The presence of calcite scale on carbon steel surface decreased the adsorption of intermediate corrosion products as the scale uniformly covered the bare surface which resulted in reduction of general CO2 corrosion rate. The results of cyclic polarization tests revealed that the bare and calcite-covered samples were not susceptible to localized CO2 corrosion under conditions studied in this research.

Neural network modelling of high pressure CO2 corrosion in pipeline steels

Abstract The effect of carbon dioxide (CO2) corrosion on pipelines is of great relevance to the petroleum as well as the Carbon Capture and Storage (CCS) industries. CO2 corrosion is responsible for lost production as it brings about the gradual degradation of pipe internals with time. The cost of general corrosion is said to be between 3 to 5% of an industrialised nation’s gross domestic product ( Schmitt et al., 2009 ; Popoola et al., 2013 ). In the U.S., the cost of corrosion in the production and manufacturing sector was $34.4 billion in 2014, with the oil and gas industry accounting for more than half ( Abbas, 2016 ). The use of neural networks (NN) as an analytic tool for corrosion data has been established however the aim of this paper is to characterise selected Matlab transfer and training functions, and assess their degree of suitability for CO2 corrosion rate prediction. Assessments of the training functions include the evaluation of the correlation coefficient (R2-value) and determination of a cumulative absolute error to indicate the level of precision and the extent of model accuracy. A NN model is developed for predicting CO2 corrosion at high partial pressures by considering the results of the various tests and analyses on the given Matlab functions. The results showed that the model is reliable with all test results falling within the 95% confidence limits. Leave-One-Out Cross-Validation (LOOCV) was implemented as a means for carrying out an additional assessment on model performance as well as for model selection from possible alternatives.