scholarly journals Effect of Magnetic Field on the Corrosion of API-5L-X65 Steel Using Electrochemical Methods in a Flow Loop

2021 ◽  
Vol 11 (19) ◽  
pp. 9329
Author(s):  
Shahid Parapurath ◽  
Arjun Ravikumar ◽  
Nader Vahdati ◽  
Oleg Shiryayev
Keyword(s):  
Magnetic Field ◽  
Carbon Steel ◽  
Corrosion Rate ◽  
Oil And Gas ◽  
Electrochemical Impedance ◽  
Polarization Curves ◽  
Corrosion Mechanism ◽  
Flow Loop ◽  
X65 Steel ◽  
Api 5L X65 Steel

Limited studies have been conducted on the effect of a magnetic field on the corrosion behavior of steels. Investigating the effect on pipeline material in the oil and gas industries will be beneficial regarding corrosion prediction and control. In this work, the effect of a magnetic field on the corrosion process of API 5L X65 carbon steel was investigated in a well-developed flow loop using potentiodynamic polarization curves and electrochemical impedance spectroscopy (EIS). Using permanent magnets and a well-designed corrosion electrode set-up, the corrosion mechanism of API 5L X65 steel was studied at different magnetic orientations and different flow conditions in a NaCl solution. The surface morphology of the corroded samples was studied using a scanning electron microscope, and the micro-morphologies of the corrosion deposits and the surface elemental composition were analyzed. The results show that the presence of a magnetic field increases the corrosion rate of API 5L X65 carbon steel, and that flow velocities and magnetic orientation have a significant influence on the anodic corrosion current. The results of the polarization curves indicate a negative shift in the Tafel curve, leading to an increase in the corrosion rate with the introduction of a magnetic field in the flow system. The results of the EIS show that the charge transfer rate is decreased when a magnetic field is applied. This work provides important direction in terms of the understanding of the combined effect of magnetism and flow on the corrosion in pipelines used in the oil and gas industries.

scholarly journals Corrosion Prediction for Corrosion Rate of Carbon Steel in Oil and Gas Environment: A Review

2018 ◽  
Vol 3 (1) ◽  
pp. 64
Author(s):  
Y P Asmara ◽  
Tedi Kurniawan
Keyword(s):  
Carbon Steel ◽  
Corrosion Rate ◽  
Environmental Conditions ◽  
Oil And Gas ◽  
Real Data ◽  
Theoretical Background ◽  
Carbon Steels ◽  
Corrosion Mechanism ◽  
Software Engineers ◽  
Materials Planning

Corrosion predictions are essential for corrosion and material engineers. It is used to prepare pre-Front End Engineering Design (pre-FEED). FEED guides to select appropriate materials, planning test schedule, work over management, and estimate future repair for cost analyses. Corrosion predictions also calculate life of pipeline and equipment systems during operational stages. As oil and gas environments are corrosive for carbon steel, it is important to account the corrosion rate of carbon steels in those environmental conditions. There are many existing corrosion predictions software, which are available in oil and gas industries. However, corrosion predictions only can be used for particular ranges of environmental conditions because they use different input parameters. To select the most applicable of corrosion predictions software, engineers have to understand theoretical background and fundamental concept of the software. This paper reviews the applications of existing corrosion prediction software in calculating corrosion rate of carbon steel in oil and gas environmental systems. The concept philosophy of software is discussed. Parameters used and range of conditions are also studied. From the results of studies, there are limitations and beneficial impacts in using corrosion software. Engineers should understand the fundamental theories of the corrosion mechanism. Knowing limitations of the models, the appropriate model can be correctly selected and interpretation of corrosion rate will close to the real data conditions.

scholarly journals The inhibition performance of mono-ethylene glycol on corrosion rate of x-80 grade carbon steel in saturated brine environment.

2020 ◽  
Vol 1 (1) ◽  
Keyword(s):  
Acetic Acid ◽  
Charge Transfer ◽  
Carbon Steel ◽  
Corrosion Rate ◽  
Ethylene Glycol ◽  
Oil And Gas ◽  
Gas Production ◽  
Electrochemical Measurements ◽  
Co2 Corrosion ◽  
Formation Water

The formation/deposition of hydrate and scale in gas production and transportation pipeline has continue to be a major challenge in the oil and gas industry. Pipeline transport is one of the most efficient, reliable and safer means of transporting petroleum products from the well sites to either the refineries or to the final destinations. Acetic acid (HAc), is formed in the formation water which also present in oil and gas production and transportation processes. Acetic acid aids corrosion in pipelines and in turn aids the formation and deposition of scales which may eventually choke off flow. Most times, Monethylene Glycol (MEG) is added into the pipeline as an antifreeze and anticorrosion agent. Some laboratory experiments have shown that the MEG needs to be separated from unwanted substance such as HAc that are present in the formation water to avoid critical conditions in the pipeline. Internal pipeline corrosion slows and decreases the production of oil and gas when associated with free water and reacts with CO2 and organic acid by lowering the integrity of the pipe. In this study, the effect of Mono-Ethylene Glycol (MEG) and Acetic acid (HAc) on the corrosion rate of X-80 grade carbon steel in CO2 saturated brine were evaluated at 25oC and 80oC using 3.5% NaCl solution in a semi-circulation flow loop set up. Weight loss and electrochemical measurements using the linear polarization resistance (LPR) and electrochemical impedance spectroscope (EIS) were used in measuring the corrosion rate as a function of HAc and MEG concentrations. The results obtained so far shows an average corrosion rate increases from 0.5 to 1.8 mm/yr at 25oC, and from 1.2 to 3.5 mm/yr at 80oC in the presence of HAc. However, there are decrease in corrosion rate from 1.8 to 0.95 mm/yr and from 3.5 to 1.6mm/yr respectively at 25oC and 80oC on addition of 20% and 80% MEG concentrations to the solution. It is also noted that the charge transfer with the electrochemical measurements (EIS) results is the main corrosion controlling mechanism under the test conditions. The higher temperature led to faster film dissolution and higher corrosion rate in the presence of HAc. The EIS results also indicate that the charge transfer controlled behaviour was as a result of iron carbonate layer accelerated by the addition of different concentrations of MEG to the system. Key words: CO2 corrosion, Carbon steel, MEG, HAc, Inhibition, Environment.

scholarly journals The Roles of H2S Gas in Behavior of Carbon Steel Corrosion in Oil and Gas Environment: A Review

2018 ◽  
Vol 7 (1) ◽  
pp. 37 ◽  
Author(s):  
Yuli Panca Asmara
Keyword(s):  
Carbon Steel ◽  
Oil And Gas ◽  
Chemical Properties ◽  
Steel Corrosion ◽  
Carbon Steels ◽  
Corrosion Mechanism ◽  
Gas Reservoir ◽  
H2s Corrosion ◽  
Carbon Dioxide Co2 ◽  
Oil And Gas Reservoir

Hydrogen sulfide (H2S) is the most dangerous element which exists in oil and gas reservoir. H2S acidifies water which causes pitting corrosion to carbon steel pipelines. Corrosion reaction will increase fast when it combines with oxygen and carbon dioxide (CO2). Thus, they can significantly reduce service life of transportation pipelines and processing facilities in oil and gas industries. Understanding corrosion mechanism of H2S is crucial to study since many severe deterioration of carbon steels pipelines found in oil and gas industries facilities. To investigate H2S corrosion accurately, it requires studying physical, electrical and chemical properties of the environment. This paper concentrates, especially, on carbon steel corrosion caused by H2S gas. How this gas reacts with carbon steel in oil and gas reservoir is also discussed. This paper also reviews the developments of corrosion prediction software of H2S corrosion. The corrosion mechanism of H2S combined with CO2 gas is also in focused. 

Effect of nickel content in the corrosion process of TiC/Cu-Ni composites immersed in synthetic seawater

MRS Advances ◽  
2019 ◽  
Vol 4 (63) ◽  
pp. 3475-3484
Author(s):  
Miguel A. Téllez-Villaseñor ◽  
Carlos A. León Patino ◽  
Ricardo Galván Martínez ◽  
Ena A. Aguilar Reyes
Keyword(s):  
Corrosion Rate ◽  
Electrochemical Impedance ◽  
Corrosion Behaviour ◽  
Nickel Content ◽  
Corrosion Mechanism ◽  
Composite Surface ◽  
Synthetic Seawater ◽  
Ni Content ◽  
The Matrix ◽  
Static Conditions

ABSTRACTThe work presents an electrochemical study of the corrosion behaviour of two TiC/Cu-Ni metal matrix composites with a content of 10 and 20 wt.% Ni immersed in synthetic seawater. The composites were synthesized by a capillary infiltration technique, obtaining dense materials TiC/Cu-10Ni and TiC/Cu-20 Ni with a residual porosity of 1.8 and 1.7%, respectively. The corrosion rate (CR) was evaluated from the techniques of polarization curves (PC), linear polarization resistance (LPR) and electrochemical impedance spectroscopy (EIS). Electrochemical measurements were carried out under static conditions, ambient temperature and atmospheric pressure at 24 hours exposure in the electrolytic medium. The corrosion rate is affected by the Ni content in the matrix, with less corrosion in the composite with a higher Ni content. The higher content of Ni in the Cu-Ni alloy provides higher passivation and stability to the corrosion products film that are absorbed on the composite surface. Microscopic examination (SEM) showed a characteristic morphology of a corrosion mechanism of the localized type (pits and crevices) generated by a differential aeration, where the TiC/Cu-10Ni composite showed greater degradation.

scholarly journals Erosion–Corrosion of 30°, 60°, and 90° Carbon Steel Elbows in a Multiphase Flow Containing Sand Particles

Materials ◽  
2019 ◽  
Vol 12 (23) ◽  
pp. 3898 ◽  
Author(s):  
Rehan Khan ◽  
Hamdan H. Ya ◽  
William Pao ◽  
Armaghan Khan
Keyword(s):  
Carbon Steel ◽  
Slug Flow ◽  
Surface Characterization ◽  
Corrosion Mechanism ◽  
Surface Imaging ◽  
Flow Loop ◽  
Erosion Corrosion ◽  
Inner Diameter ◽  
Corrosion Pits ◽  
Microscopic Surface

Erosion–corrosion in flow changing devices as a result of sand transportation is a serious concern in the hydrocarbon and mineral processing industry. In this work, the flow accelerated erosion–corrosion mechanism of 90°, 60°, and 30° long radius horizontal–horizontal (H–H) carbon steel elbows with an inner diameter of 50.8 mm were investigated in an experimental closed-flow loop. For these geometrical configurations, erosion–corrosion was elucidated for erosive slug flow regimes and the extent of material degradation is reported in detail. Qualitative techniques such as multilayer paint modeling and microscopic surface imaging were used to scrutinize the flow accelerated erosion–corrosion mechanism. The 3D roughness characterization of the surface indicates that maximum roughness appears in downstream adjacent to the outlet of the 90° elbow. Microscopic surface imaging of eroded elbow surfaces disseminates the presence of corrosion pits on the exit regions of the 90° and 60° elbows, but erosion scars were formed on the entry regions of the 30° elbow. Surface characterization and mass loss results indicated that changing the elbow geometrical configuration from a small angle to wide angle significantly changed the mechanical wear mechanism of the tested elbows. Moreover, the maximum erosive location was identified at the top of the horizontally-oriented elbow for slug flow.

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 Effect of pH in SRB (ATCC 7757) Growth for Oil and Gas API X 70 Steel Pipes

2019 ◽  
Vol 3 (1) ◽  
pp. 30-36
Author(s):  
Zuraini Din ◽  
Keyword(s):  
Carbon Steel ◽  
Corrosion Rate ◽  
Oil And Gas ◽  
Desulfovibrio Desulfuricans ◽  
Oil And Gas Industry ◽  
Gas Industry ◽  
Corrosion Failure ◽  
Bacteria Growth ◽  
Steel Pipes ◽  
Metal Pipes

In the oil and gas industry, pipeline is the major transportation medium to deliver the products. According to [1] containment of pipeline loss to indicate that corrosion has been found to be the most predominant cause for failures of buried metal pipes. MIC has been identified as one of the major causes of underground pipeline corrosion failure and Sulphate Reducing Bacteria (SRB) are the main reason causing MIC, by accelerating corrosion rate. The objectives of this study is to study the SRB growth, Desulfovibrio desulfuricans ATCC 7757 due to pH and determine the optimum value controlling the bacteria growth on the internal pipe of carbon steel grade API X70. The result shows that the optimum SRB growth is at range pH 5-5 to 6.5 and the exposure time of 7 to 14 days. At pH 6.5 the maximum corrosion rate is 1.056 mm/year. Corrosion phenomena on carbon steel in the study proven had influence by pH and time. From this result pitting corrosion strongly attack at carbon steel pipe. In the future project, it is recommended to study the effect of different pipe location for example the pipeline under seawater.

scholarly journals Beyond Carbon Steel: Detecting Wellbore Shape and Cavities, and Cement Imperfections in Cased Wells

Energies ◽  
2019 ◽  
Vol 12 (21) ◽  
pp. 4211
Author(s):  
Timofey Eltsov ◽  
Tadeusz W. Patzek
Keyword(s):  
Magnetic Field ◽  
Carbon Steel ◽  
Oil Recovery ◽  
Magnetic Permeability ◽  
Carbon Capture ◽  
Oil And Gas ◽  
Carbon Capture And Storage ◽  
Vertical Component ◽  
Co2 Injection ◽  
Gas Field

The non-corrosive, electrically resistive fiberglass casing materials may improve the economics of oil and gas field projects. At moderate temperatures (<120 °C), fiberglass casing is superior to carbon steel casing in applications that involve wet CO2 injection and/or production, such as carbon capture and storage, and CO2-based enhanced oil recovery (EOR) methods. Without a perfect protective cement shell, carbon steel casing in contact with a concentrated formation brine corrodes and the fiberglass casing is superior again. Fiberglass casing enables electromagnetic logging for exploration and reservoir monitoring, but it requires the development of new logging methods. Here we present a technique for the detection of integrity of magnetic cement behind resistive fiberglass casing. We demonstrate that an optimized induction logging tool can detect small changes in the magnetic permeability of cement through a non-conductive casing in a vertical (or horizontal) well. We determine both the integrity and solidification state of the cement-filled annulus behind the casing. Changes in magnetic permeability influence mostly the real part of the vertical component of the magnetic field. The signal amplitude is more sensitive to a change in the magnetic properties of the cement, rather than the signal phase. Our simulations showed that optimum separation between the transmitter and receiver coils ranged from 0.25 to 0.6 m, and the most suitable magnetic field frequencies varied from 0.1 to 10 kHz. A high-frequency induction probe operating at 200 MHz can measure the degree of solidification of cement. The proposed method can detect borehole cracks filled with cement, incomplete lift of cement, casing eccentricity, and other borehole inhomogeneities.

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