scholarly journals Effect of CO2 Partial Pressure on the Corrosion Behavior of J55 Carbon Steel in 30% Crude Oil/Brine Mixture

Materials ◽  
2018 ◽  
Vol 11 (9) ◽  
pp. 1765 ◽  
Author(s):  
Haitao Bai ◽  
Yongqing Wang ◽  
Yun Ma ◽  
Qingbo Zhang ◽  
Ningsheng Zhang
Keyword(s):  
Carbon Steel ◽  
Corrosion Rate ◽  
Crude Oil ◽  
Partial Pressure ◽  
Initial Period ◽  
Localized Corrosion ◽  
Corrosion Mechanism ◽  
Corrosion Properties ◽  
Co2 Partial Pressure ◽  
Corrosion Scale

The influence of CO2 partial pressure on the corrosion properties, including corrosion rate, morphology, chemical composition, and corrosion depth, of J55 carbon steel in 30% crude oil/brine at 65 °C was investigated. A corrosion mechanism was then proposed based on the understanding of the formation of localized corrosion. Results showed that localized corrosion occurred in 30% crude oil/brine with CO2. The corrosion rate sharply increased as the CO2 partial pressure (P co 2 ) was increased from 0 to 1.5 MPa, decreased from P co 2 = 1.5 MPa to P co 2 = 5.0 MPa, increased again at P co 2 = 5.0 MPa, and then reached a constant value after P co 2 = 9.0 MPa. The system pH initially decreased, rapidly increased, and then stabilized as CO2 partial pressure was increased. In the initial period, the surface of J55 carbon steel in the CO2/30% crude oil/brine mixtures showed intense corrosion. In conclusion, CO2 partial pressure affects the protection performance of FeCO3 by changing the formation of corrosion scale and further affecting the corrosion rate.

scholarly journals Evaluation the Effect of Velocity and Temperature on the Corrosion Rate of Crude Oil Pipeline in the Presence of CO2/H2S Dissolved Gases

2019 ◽  
Vol 20 (2) ◽  
pp. 41-50
Author(s):  
Haider Hadi Jasim
Keyword(s):  
Carbon Steel ◽  
Corrosion Rate ◽  
Crude Oil ◽  
Computer Software ◽  
Test Technique ◽  
Co2 Partial Pressure ◽  
Oil Pipeline ◽  
Low Degree ◽  
Oil Flow ◽  
Static Conditions

In this paper investigate the influences of dissolved CO2/H2S gases, crude oil velocity and temperature on the rate of corrosion of crude oil transmission pipelines of Maysan oil fields southern Iraq. The Potentiostatic corrosion test technique was conducted into two types of carbon steel pipeline (materials API 5L X60 and API 5L X80). The computer software ECE electronic corrosion engineer was used to predict the influences of CO2 partial pressure, the composition of crude oil, flow velocity of crude oil and percentage of material elements of carbon steel on the rate of corrosion. As a result, the carbon steel API 5L X80 indicates good and appropriate resistance to corrosion compared to carbon steel API 5L X60. The rate of corrosion acquired from the test in flow conditions is most significant than that in static conditions. The crude oil from Noor field has the largest value of corrosion rate, while the crude oil from Halfaya field has the lower value; other crude oils have moderate values. The dissolved CO2/H2S gases contribute by a low degree in internal pipeline corrosion because of the small concentrations.

Corrosion Behavior of X70 Pipeline Steel and Corrosion Rate Prediction Under the Combination of Corrosive Medium and Applied Pressure

2017 ◽  
Author(s):  
Kaikai Li ◽  
Wei Wu ◽  
Guangxu Cheng ◽  
Yun Li ◽  
Haijun Hu ◽  
...  
Keyword(s):  
Natural Gas ◽  
Corrosion Rate ◽  
Tensile Stress ◽  
Partial Pressure ◽  
Corrosion Behavior ◽  
Pipeline Steel ◽  
Applied Pressure ◽  
Chloride Concentration ◽  
X70 Pipeline Steel ◽  
Co2 Partial Pressure

Natural gas transmission pipeline is prone to internal corrosion due to the combination of corrosive impurities in the pipe (such as CO2, H2S and chlorides) and applied pressure of the pipeline, which seriously affects the safe operation of the pipeline. In this work, the corrosion behavior of a typical X70 pipeline steel was investigated by using potentiodynamic polarization and electrochemical impendence spectroscopy (EIS). The polarization and EIS data under different CO2 partial pressures (0–1 atm), H2S concentrations (0–150 ppm), chloride concentrations (0–3.5 wt%) and tensile stress (0–400 MPa) were obtained. The results show that corrosion rate increases with the increase of CO2 partial pressure and chloride concentration, respectively, while first increases and then decreases with the increase H2S concentrations. The corrosion rate is less affected by elastic tensile stress. In addition, a quantitative prediction model for corrosion rate of natural gas pipeline based on adaptive neuro-fuzzy inference system (ANFIS) was established by fitting the experimental data which maps the relationship between the key influencing factors (i.e. CO2 partial pressure, H2S concentration, chloride concentration and tensile stress) and the corrosion rate. The prediction results show that the relative percentage errors of the predicted and experimental values are relatively small. The prediction accuracy of the model satisfies the engineering application requirement.

Optimizing CAPEX and OPEX for High CO2 and H2S Field by Using Mechanistic Corrosion Modelling Approach

2021 ◽  
Author(s):  
Ahmad Fahdlam Saleh ◽  
Muhammad Zaid Kamardin ◽  
Shahrun Nizam Safiin ◽  
Mohd Farizan Ahmad
Keyword(s):  
Corrosion Rate ◽  
Partial Pressure ◽  
Gas Production ◽  
Co2 Corrosion ◽  
Original Design ◽  
Co2 Partial Pressure ◽  
Field Development ◽  
Stage Of Development ◽  
Corrosion Modelling ◽  
Modelling Approach

Abstract The gas contaminants especially CO2 and H2S from the well is a major threat to oil and gas production facilities and pipeline. Developing this type of reservoir cost enormous CAPEX and OPEX due the need for expensive materials or the need of continuous chemical injection. This paper outlines the opportunity of cost optimization for future field development and operational through mechanistic corrosion modelling approach. This method was embedded to an in-house corrosion prediction model that was first developed by collaboration with Ohio University in 2008 with capability to predict corrosion rate for partial pressure more than 20bar of CO2 and up to 1bar of H2S. The model validation was performed based on actual field production operated at 55°C and 22 bar of CO2 partial pressure followed the methodology as outlined in NACE paper C2012-0001449. Upon successful validation, the model has been deployed to assist an Operator of an offshore pipeline in Southeast Asia, operating at 97°C and 17 bar of CO2 partial pressure, to ascertain the risk due to CO2 corrosion and review the original pipeline design adequacy. Subsequently, the model has been utilized for an Operator of onshore facilities in Middle East to address specific issue encountered during the final stage of development for one of the wellpad in which the wells are expected to experience increase of H2S from 100ppm in original design to more than 1000ppm during actual production. This process changes raised a serious concern on the integrity of the materials as potential corrosion issue and the need for corrosion mitigation such as H2S Scavenger injection was not originally considered during early stage of engineering. The corrosion rate from the model has been validated against the intelligent pigging (IP) data and proven to be able to predict corrosion rate with +20% accuracy and more than 99% confidence level for CO2 partial pressure up to 25 bar with the presence of H2S. Based on deployment and utilization of the model, the high confidence in the model ability to accurately predict the corrosion rate will lead to potential CAPEX and OPEX optimization for the field development and during operational stage.

scholarly journals Effect of CO2 Partial Pressure on the Corrosion Inhibition of N80 Carbon Steel by Gum Arabic in a CO2-Water Saline Environment for Shale Oil and Gas Industry

Materials ◽  
2020 ◽  
Vol 13 (19) ◽  
pp. 4245
Author(s):  
Gaetano Palumbo ◽  
Kamila Kollbek ◽  
Roma Wirecka ◽  
Andrzej Bernasik ◽  
Marcin Górny
Keyword(s):  
Carbon Steel ◽  
Partial Pressure ◽  
Corrosion Inhibition ◽  
Photoelectron Spectroscopy ◽  
Inhibition Efficiency ◽  
Gum Arabic ◽  
Saline Environment ◽  
X Ray ◽  
Co2 Partial Pressure ◽  
Corrosion Inhibition Efficiency

The effect of CO2 partial pressure on the corrosion inhibition efficiency of gum arabic (GA) on the N80 carbon steel pipeline in a CO2-water saline environment was studied by using gravimetric and electrochemical measurements at different CO2 partial pressures (e.g., PCO2 = 1, 20 and 40 bar) and temperatures (e.g., 25 and 60 °C). The results showed that the inhibitor efficiency increased with an increase in inhibitor concentration and CO2 partial pressure. The corrosion inhibition efficiency was found to be 84.53% and 75.41% after 24 and 168 h of immersion at PCO2 = 40 bar, respectively. The surface was further evaluated by scanning electron microscopy (SEM), energy dispersive spectroscopy (EDS), grazing incidence X-ray diffraction (GIXRD), and X-ray photoelectron spectroscopy (XPS) measurements. The SEM-EDS and GIXRD measurements reveal that the surface of the metal was found to be strongly affected by the presence of the inhibitor and CO2 partial pressure. In the presence of GA, the protective layer on the metal surface becomes more compact with increasing the CO2 partial pressure. The XPS measurements provided direct evidence of the adsorption of GA molecules on the carbon steel surface and corroborated the gravimetric results.

The Effect of the Partial Pressure of H2S and CO2 on the Permeation of Hydrogen in Carbon Steel by Using Pressure Buildup Techniques

CORROSION ◽  
10.5006/3128 ◽  
2019 ◽  
Vol 75 (10) ◽  
pp. 1207-1215
Author(s):  
Nayef M. Alanazi ◽  
Abdullah A. Al-Enezi
Keyword(s):  
Steady State ◽  
Carbon Steel ◽  
Corrosion Rate ◽  
Partial Pressure ◽  
Hydrogen Permeation ◽  
Measurement Techniques ◽  
Permeation Rate ◽  
Pressure Buildup ◽  
Hydrogen Flux ◽  
The Relationship

There are concerns in the industry about using an electrochemical technique for actual hydrogen permeation measurements where charging current is not a field condition. The objective of this work is to use pressure buildup techniques to study the influence of H2S and CO2 partial pressure on the relationship between hydrogen permeation and corrosion rate measured by different techniques. Sulfide films formed on carbon steel in a solution containing 5 wt% NaCl and 0.5 wt% acidic acid at various H2S and CO2 partial pressures were characterized, and the effect of the film on hydrogen permeation was also investigated. Field conditions were included in this study for comparison purposes. The relationship was modeled at the steady state of both hydrogen flux and corrosion rate. The results confirmed by use of two hydrogen flux measurement techniques (eudiometer and high-pressure buildup probe) and two corrosion measurement methods (weight loss coupons and coupled multiarray electrode system), that there is no direct correlation between hydrogen flux and corrosion rate. Therefore, the hydrogen permeation rate in H2S and CO2 environments was found to be more controlled by partial pressure of H2S than corrosion rate. The amount of descent in hydrogen flux, after reaching maximum of hydrogen permeation rate and before reaching a steady state, depends on the morphology and structure of corrosion films which are mainly controlled by concentration of H2S.

scholarly journals Corrosion of Carbon Steel in Artificial Geothermal Brine: Influence of Carbon Dioxide at 70 °C and 150 °C

Materials ◽  
2019 ◽  
Vol 12 (22) ◽  
pp. 3801 ◽  
Author(s):  
Gabriela Aristia ◽  
Le Quynh Hoa ◽  
Ralph Bäßler
Keyword(s):  
Carbon Dioxide ◽  
Carbon Steel ◽  
Temperature Effect ◽  
Electrochemical Impedance ◽  
Corrosion Products ◽  
Localized Corrosion ◽  
Corrosion Mechanism ◽  
Sem Images ◽  
Geothermal Brine ◽  
Corrosive Effect

This study focuses on the corrosion mechanism of carbon steel exposed to an artificial geothermal brine influenced by carbon dioxide (CO2) gas. The tested brine simulates a geothermal source in Sibayak, Indonesia, containing 1500 mg/L of Cl−, 20 mg/L of SO42−, and 15 mg/L of HCO3− with pH 4. To reveal the temperature effect on the corrosion behavior of carbon steel, exposure and electrochemical tests were carried out at 70 °C and 150 °C. Surface analysis of corroded specimens showed localized corrosion at both temperatures, despite the formation of corrosion products on the surface. After 7 days at 150 °C, SEM images showed the formation of an adherent, dense, and crystalline FeCO3 layer. Whereas at 70 °C, the corrosion products consisted of chukanovite (Fe2(OH)2CO3) and siderite (FeCO3), which are less dense and less protective than that at 150 °C. Control experiments under Ar-environment were used to investigate the corrosive effect of CO2. Free corrosion potential (Ecorr) and electrochemical impedance spectroscopy (EIS) confirm that at both temperatures, the corrosive effect of CO2 was more significant compared to that measured in the Ar-containing solution. In terms of temperature effect, carbon steel remained active at 70 °C, while at 150 °C, it became passive due to the FeCO3 formation. These results suggest that carbon steel is more susceptible to corrosion at the near ground surface of a geothermal well, whereas at a deeper well with a higher temperature, there is a possible risk of scaling (FeCO3 layer). A longer exposure test at 150 °C with a stagnant solution for 28 days, however, showed the unstable FeCO3 layer and therefore a deeper localized corrosion compared to that of seven-day exposed specimens.

The Electrochemical Characteristics of Corrosion Scale on P110 Carbon Steel

2011 ◽  
Vol 287-290 ◽  
pp. 2332-2338
Author(s):  
Jian Miao ◽  
Shi Dong Zhu ◽  
Qiang Wang ◽  
Yao Rong Feng ◽  
Xin Wei Zhao
Keyword(s):  
Carbon Steel ◽  
Corrosion Rate ◽  
Polarization Resistance ◽  
Electrochemical Impedance ◽  
Electrode Reaction ◽  
Reaction Process ◽  
Electrochemical Characteristics ◽  
Experimental Time ◽  
Corrosion Scale

The properties of corrosion scale on P110 carbon steel in the saltwater solution containing CO2 have been examined by electrochemical impedance spectroscope (EIS). The change of electrode reaction process on the corrosion scale has been discussed in the present work. It is found that the corrosion rate decreases with the increasing of the experimental time, and the reducing tendency of corrosion rate becomes low as the experimental time was 72 hours, EIS results indicate that the polarization resistance increases gradually and the electrode reaction is controlled by both diffusion and activation in comparison with activation only at the beginning.

scholarly journals Corrosion Mechanism of L360 Pipeline Steel Coated with S8 in CO2-Cl− System at Different pH Values

Metals ◽  
2021 ◽  
Vol 11 (12) ◽  
pp. 1975
Author(s):  
Fan Wang ◽  
Jinling Li ◽  
Chengtun Qu ◽  
Tao Yu ◽  
Yan Li ◽  
...  
Keyword(s):  
Pipeline Steel ◽  
Localized Corrosion ◽  
Corrosion Mechanism ◽  
X Ray Diffraction ◽  
Intensity Index ◽  
Corrosion Scale ◽  
Electrode Cell ◽  
Corrosion Intensity ◽  
Acidic Conditions ◽  
Wire Beam Electrode

The corrosion behavior of L360 pipeline steel coated with or without elemental sulfur (S8) in CO2–Cl− medium at different pH was studied. An autoclave was used to simulate the working conditions for forming the corrosion scale, and an electrochemical workstation with a three-electrode cell was used to analyze the electrochemical characterization of the corrosion scale. A wire beam electrode was used to determine the potential and current distribution, and scanning electron microscopy and X-ray diffraction were used to characterize the morphology and composition of the corrosion scale. The results showed that the deposition of S8 on the surface of the electrodes caused serious localized corrosion, especially under acidic conditions. The morphology and localized corrosion intensity index further proved that the deposition of S8 significantly promoted corrosion, especially pitting corrosion. Finally, a novel corrosion mechanism of L360 pipeline steel coated with S8 in a CO2-Cl− environment under acidic conditions was proposed, and we then modeled the theoretical mechanisms that explained the experimental results.

Effect of heat treatment on microstructure and corrosion resistance of extruded ZK80 Mg alloy

2019 ◽  
Vol 9 (9) ◽  
pp. 1092-1099
Author(s):  
Fenghong Cao ◽  
Chang Chen ◽  
Zhenyu Wang
Keyword(s):  
Heat Treatment ◽  
Corrosion Resistance ◽  
Corrosion Rate ◽  
Aging Time ◽  
Room Temperature ◽  
Aging Treatment ◽  
Corrosion Process ◽  
Corrosion Mechanism ◽  
Nacl Solution ◽  
Corrosion Properties

The corrosion characteristics and corrosion mechanism of the extruded ZK80 alloy with different states soaking in 3.5% NaCl solution at room temperature were analyzed via OM, SEM, EDS, XRD and static weightlessness method and other experimental analysis methods. The results show that when the aging temperature is constant, and the corrosion rate decreases with the lengthen of aging time, while when the corrosion time is constant, the corrosion rate increases with the increase in aging time. Appropriate aging treatment not only refines the grain of the alloy, but also precipitates the Mg–Zn phase which can effectively prevent the corrosion process and improve the anti-corrosion properties of the alloy. The main corrosion characteristics of the alloy are filamentary corrosion and pitting corrosion.

Effect of Sulfuric Acid Concentration on the Corrosion Rate of ASTM A213-T12 Steel

2020 ◽  
Vol 867 ◽  
pp. 213-217
Author(s):  
Suwarno ◽  
Muhammad Nashir
Keyword(s):  
Sulfuric Acid ◽  
Carbon Steel ◽  
Corrosion Rate ◽  
Sulfuric Acid Concentration ◽  
Solution Concentration ◽  
Immersion Test ◽  
Corrosion Properties ◽  
Acid Molarity ◽  
Mechanical And Corrosion Properties ◽  
Corrosion Of Steel

Even though carbon steel is susceptible to corrosion degradation, carbon steel is widely used for applications in the industry. Impurities in steel composition are known to affect the mechanical and corrosion properties. There are many studies on the corrosion of steel, but for a specific application, further research still required. The present work is conducted to determine the effect of low concentration of sulfuric acid on the corrosion rate of power plant steel ASTM A213-T12 with a solution concentration from 0.01-0.05 M H2SO4. The corrosion rate was determined by using an immersion test as well as a polarization method using a potentiostat. The result shows that increasing the concentration of sulfuric acid molarity, the corrosion rate tended to increase. Furthermore, the effect of phosphor contents significantly affects the corrosion rate in which steel with high phosphor contents has a high corrosion rate.

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