Effect of Temperature and H2S Concentration on Corrosion of X52 Pipeline Steel in Acidic Solutions

The corrosion behavior of X52 pipeline steel in H2S solutions was investigated through immersion corrosion test which was carried out in a high temperature and high pressure autoclave at different temperatures and H2S concentrations. General corrosion rates were calculated based on the weight loss of samples. The morphology and the chemical composition of the corrosion products were obtained by Scanning Electron Microscopy (SEM) and Energy Dispersive Spectroscopy (EDS). The crystal structure of corrosion products was analyzed by X-Ray diffraction patterns (XRD). The corrosion products consisted mainly of the sulfide compounds (mackinawite, cubic ferrous sulfide, troilite and pyrrhotite). The corrosion products included two layers: the inner iron-rich layer and the outer sulfur-rich layer. Under H2S concentrations of 27g/L, the corrosion rate increased with the increase of temperature up to 90°C and then decreased at 120°C, finaly increased again. The corrosion rate first increased with H2S concentrations then decreased at 120°C. The structure and stability of the corrosion products due to different corrosion mechanism had a major impact on the corrosion rate. The corrosion resistance of the corrosion products increased as follows: mackinawite < cubic ferrous sulfide < troilite < pyrrhotite.

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Effect of Temperature on H2S/CO2 Corrosion Behaviors of P110-3Cr Steel

Advanced Materials Research ◽

10.4028/www.scientific.net/amr.816-817.54 ◽

2013 ◽

Vol 816-817 ◽

pp. 54-59 ◽

Cited By ~ 1

Author(s):

Xin Su ◽

Jian Bo Sun ◽

Chong Sun ◽

Bin Han

Keyword(s):

Corrosion Rate ◽

Corrosion Product ◽

Iron Sulfide ◽

Energy Dispersive Spectrometer ◽

Corrosion Products ◽

Effect Of Temperature ◽

General Corrosion ◽

X Ray Diffraction ◽

X Ray ◽

Corrosion Behaviors

Flowing solution environment containing H2S/CO2was simulated by high temperature and high pressure autoclave. Corrosion behaviors of P110-3Cr pipeline steels were investigated by Weight loss, Scanning electron microscopy (SEM), X-Ray diffraction (XRD) and Energy dispersive spectrometer (EDS). Effect of temperature on corrosion rate and corrosion product was discussed. The results showed that corrosion rate of P110-3Cr steel decrease at the beginning and then increased with rising temperature. The corrosion types are general corrosion. P110-3Cr has resistance to local corrosion. Mackinawite (FeS0.9) is formed as corrosion product in low-temperature condition. With temperature increasing the corrosion products are dominated by mackinawite (FeS0.9) and Cubic iron sulfide (Fe3S4). When temperature increased to 150 ¡æ, the corrosion products are made up of Hexagonal iron sulfide (Fe0.96S) and Orthorhombic Marcasite (FeS2). No siderite (FeCO3) is detected, the corrosion is controlled by H2S; Cr is rich in the corrosion scale.

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Early Corrosion Behavior of Pipeline Steel Containing 1% Cr in Sea Water Environment

Advanced Materials Research ◽

10.4028/www.scientific.net/amr.1120-1121.773 ◽

2015 ◽

Vol 1120-1121 ◽

pp. 773-778

Author(s):

Zhen Guang Liu ◽

Xiu Hua Gao ◽

Lin Xiu Du ◽

Jian Ping Li ◽

Ping Ju Hao

Keyword(s):

Corrosion Rate ◽

Corrosion Behavior ◽

Sea Water ◽

Pipeline Steel ◽

Water Environment ◽

Corrosion Products ◽

Immersion Experiment ◽

Three Stages ◽

Stage 1 ◽

Microscopic Surface

The corrosion behavior of pipeline steel containing 1%Cr is studied by using immersion experiment. The corrosion rust is characteried with macroscopic/microscopic surface morphology, corrosion kinetics and corrosion phases. The results demonstrate that the main corrosion products are lepidocrocite and goethite, Cr-rich compound consists of the inner layer. The corrosion process could be divided into three stages. At stage 1, the corrosion rate decreases fast, and the distributed corrosion products are formed. At stage 2, the granular corrosion products appear on coupons surface gradually, and a plain corrosion rate is obtained. At stage 3, a compact and dense corrosion layer attaches to coupons surface, and corrosion rate decreases mildly.

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On the Corrosion Mechanism of CO2 Transport Pipeline Steel Caused by Condensate: Synergistic Effects of NO2 and SO2

Materials ◽

10.3390/ma12030364 ◽

2019 ◽

Vol 12 (3) ◽

pp. 364 ◽

Cited By ~ 4

Author(s):

Le Quynh Hoa ◽

Ralph Baessler ◽

Dirk Bettge

Keyword(s):

Chemical Nature ◽

Reaction Kinetic ◽

Pipeline Steel ◽

Synergistic Effects ◽

Corrosion Mechanism ◽

General Corrosion ◽

X Ray ◽

Co2 Transport ◽

Co2 Flow ◽

Acidic Components

To study the effects of condensed acid liquid, hereafter referred to as condensate, on the CO2 transport pipeline steels, gas mixtures containing a varying concentration of H2O, O2, NO2, and SO2, were proposed and resulted in the condensate containing H2SO4 and HNO3 with the pH ranging from 0.5 to 2.5. By exposing the pipeline steel to the synthetic condensate with different concentration of acidic components, the corrosion kinetic is significantly changed. Reaction kinetic was studied using electrochemical methods coupled with water analysis and compared with surface analysis (scanning electron microscopy (SEM), energy-dispersive X-ray spectroscopy (EDS), and X-ray diffractometry (XRD)) of corroded coupons. The results showed that, although the condensation of NO2 in the form of HNO3 causes faster general corrosion rate, it is the condensation of SO2 in the form of H2SO4 or the combination of SO2 and NO2 that may cause much more severe problems in the form of localized and pitting corrosions. The resulting corrosion forms were depended on the chemical nature of acids and their concentration at the same investigated pH. The effects of changing CO2 flow rate and renewing condensate on pitting corrosion were further studied.

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Microbiologically Influenced Corrosion Combined with Under-Deposit Corrosion Mechanism and Control Technology in Water Injection Wells of Middle East Carbonate Oilfield

10.2523/iptc-21343-ms ◽

2021 ◽

Author(s):

Zhengrong Ye ◽

Huachang Chi ◽

Xiang Zhou ◽

Zhiwen Yang ◽

Weidong Jiang ◽

...

Keyword(s):

Middle East ◽

Corrosion Rate ◽

High Salinity ◽

Water Injection ◽

Corrosion Products ◽

Microbiologically Influenced Corrosion ◽

Corrosion Mechanism ◽

Corrosion Prevention ◽

High Hydrogen ◽

Corrosion Failure

Abstract A carbonate oilfield in the Middle East carries out the mixed water injection of produced water and fresh water, after 1 year of its rapid exploration. The injected water is highly corrosive, with high salinity, high chloride concentration and high hydrogen sulfide. Recently, there are dozens of corrosion perforations on L80 tubing in injectors within 2 years in the field and the corrosion rate reaches 3.6 mm/a. After the tubing leaks, the injected water enters into the annulus between the tubing and casing, which causes casing corrosion, damages the well integrity, and greatly influences the field production. In this paper, the causes for such rapid tubing corrosion failure are investigated by using optical metallographic microscopy, scanning electron microscopy (SEM), energy dispersive spectrometer (EDS) X-ray diffraction (XRD), and combined with the weight loss and bacteria testing. Firstly, test the element composition of the L80 tubing to verify the tubing quality. Secondly, conduct the corrosion experiments of H2S and dissolved oxygen. Thirdly, analyze the morphology and corrosion product composition of failure tubing. The results indicate that the failed L80 tubing material meets the requirements of API SPEC 5CT-2011 standard. The localized corrosion rate of L80 is 0.293~0.697 mm/a at whole well depth in the simulated injection water. Bacteria were detected in both the injected water and the corrosion products of the failed tubing. In addition, the corrosion products of failed tubing are mainly FeS, CaCO3 and Fe3O4, which indicates that the synergistic effect of microbiologically influenced corrosion and under-deposited corrosion promote the perforation of tubing. Then the corrosion prevention strategy of UHMWPE lined tubing was proposed. UHMWPE lined tubing has been applied in nine water injectors. After one year and a half, one of the water injector’s UHMWPE lined tubing has been detected, no corrosion perforations observed, and the scale deposition became slightly. This case provides useful practical experience for corrosion prevention of high salinity and high acid injection well in carbonate oilfields.

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Role of Mexican Clay Soils on Corrosiveness and Stress Corrosion Cracking of Low-Carbon Pipeline Steels: A Case Study

CORROSION ◽

10.5006/3515 ◽

2020 ◽

Vol 76 (10) ◽

pp. 967-984

Author(s):

A. Contreras ◽

L.M. Quej ◽

H.B. Liu ◽

J.L. Alamilla ◽

E. Sosa

Keyword(s):

Corrosion Rate ◽

Stress Corrosion ◽

Stress Corrosion Cracking ◽

Corrosion Cracking ◽

The State ◽

Clay Soils ◽

Corrosion Mechanism ◽

General Corrosion ◽

Southern Mexico ◽

Gauge Section

This work analyzed the physicochemical effect of different types of Mexican clay soils on corrosion and stress corrosion cracking (SCC) behavior in contact with X60 and X65 steels. Four soils were obtained from the right of way land in southern Mexico at 1.5 m depth close to pipelines. Two soils were from the state of Oaxaca (SO1 and SO2), and two others from the state of Veracruz (SV1 and SV2). Physicochemical and textural analysis of soils was performed and correlated to SCC susceptibility and corrosion mechanism. It was observed that soil texture might be related to corrosivity. A texture index (ratio between sand and silt + clay), which was seen to have a relationship with the corrosive tendency of soils, was estimated. It showed that soil with a higher index (SV1) has a higher corrosion rate. Electrochemical impedance spectroscopy and polarization curves were performed and correlated to the corrosion rate and the SCC susceptibility of steels. Steels exposed to SV1 soil exhibited a higher corrosion rate related to a higher content of chlorides and acid pH than those seen in other soils, which resulted in the pitting of such steels. Two types of corrosion were observed. Soils from SV1 and SV2 generated pitting, and soils from SO1 and SO2 produced general corrosion. Inclusions caused pitting in the gauge section of X60 and X65 steels exposed to SV1 soil by anodic dissolution. Galvanic coupling between inclusions and the base metal and dissolution of the inclusions might have enhanced the nucleation of pits at these sites. SCC susceptibility was evaluated using slow strain rate tests (SSRT). After SSRT, the fracture surfaces were analyzed through scanning electron microscopy. The SCC index obtained from SSRT indicates that X60 and X65 steels exhibited good resistance to SCC. A highly corrosive soil, such as SV1, causes the formation of pits instead of cracks, which is attributed to the dissolution process; however, lower SCC indexes were obtained for this system. The higher corrosion resistance of X60 steel is related to a more homogenous microstructure and a higher content of elements, such as Ni and Cr, than those of X65 steel that decrease the corrosion rate.

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Possible Missing Link in CO2 Corrosion Prediction

10.2118/205056-ms ◽

2021 ◽

Author(s):

Yves Gunaltun

Keyword(s):

Corrosion Rate ◽

Field Experience ◽

Prediction Models ◽

Co2 Corrosion ◽

Corrosion Mechanism ◽

General Corrosion ◽

Flat Bottom ◽

Research Results ◽

Corrosion Rates ◽

The Impact

Abstract CO2 corrosion prediction models predict a general corrosion rate, but field failures are due to localised CO2 corrosion. That is why predicted corrosion rates are correlated to a corrosivity level. These models generally consider that the corrosion rate remains, after the initiation period, unchanged as long as operating and/or production parameters remain unchanged. However, 25 years of field experience and also some recent research results confirmed that after an initial phase of high corrosion rates, the CO2 corrosion rates may significantly decrease with time forming flat-bottom large corrosion features (mesa corrosion) and stabilise. Depending on the corrosivity level the time needed for the stabilisation would be up to about 12 months. To be noted that the stabilization has been known since 2003-2004. It was first used in 2005 for the development of two gas fields with success. In 2008, it was used for the prediction of the remaining life of gas pipelines transporting very corrosive wet gas. The use of costly CRA / cladded pipes was avoided. Gunaltun Y. and call. made the first publication about the importance of the stabilization on the remaining pipeline service life in 2009. Then, possible mechanisms of stabilization were published by Gunaltun Y. in 2012 and Gunaltun Y. and call. 2013. In the present paper the field experience, the research results and the mechanisms leading to stabilisation are discussed in detail and summarised. The main driving force is the galvanic action between anodic and cathodic zones. The clustering of corrosion features completes the process of stabilisation. Re-initiation of corrosion, after stabilisation, has not been observed neither in the laboratory nor in field. The reasons why stabilisation is a non-reversible process are also explained in detail. The conclusions are integrated in the general understanding of CO2 corrosion mechanism. Then a new method is proposed to complete the corrosion prediction approaches used by the industry. Even though some research is still needed to validate the impact of some parameters involved in the stabilisation process, the stabilisation concept is now mature enough for including it in the prediction models. It is very likely that stabilisation is one of the missing links in CO2 corrosion prediction chain.

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Corrosion Inhibition of Carbon Steel Using Chitosan as an inhibitor in 3.5% NaCl Medium

International Journal of Eco-Innovation in Science and Engineering ◽

10.33005/ijeise.v1i02.32 ◽

2020 ◽

Vol 1 (02) ◽

pp. 20-25

Author(s):

Lilik Suprianti ◽

Dwi Hery Astuti ◽

Sukamto ◽

Khafid Ubay Ilyas ◽

Ellyn Evina Ellys Simanjuntak

Keyword(s):

Sodium Chloride ◽

Carbon Steel ◽

Corrosion Rate ◽

Corrosion Inhibition ◽

Potentiodynamic Polarization ◽

Effect Of Temperature ◽

Strong Electrolyte ◽

Chitosan Concentration ◽

Different Temperatures ◽

Marine Applications

Carbon steel is a metal that is widely used for the construction of industrial and marine applications. Hence, seawater is one of the corrosive mediums due to its Natrium Chloride (NaCl) content as a strong electrolyte. One method to control the corrosion rate is by adding the inhibitor. Chitosan has been chosen as inhibitor corrosion because of non-poisonous and green material. Corrosion inhibition of carbon steel in chitosan inhibitor presence in 3,5% NaCl medium was studied using potentiodynamic polarization technique. This study aims to understand the effect of temperature and inhibitor concentration on carbon steel's corrosion behavior. This study also determined adsorption constant value of chitosan on the carbon steel surface. The corrosion rate has been analyzed by using potentiodynamic polarization. Firstly, carbon steel is prepared by cutting them in cuboid shape by dimensions 4cmx 1cm x 3mm. Secondly, a 3.5 % sodium chloride solution is prepared by dilute NaCl crystal into demineralized water. The next step is inhibitor preparation by dissolve chitosan powder in the acid solution. The corrosion rate is analyzed in different temperatures, various from 30-70oC, and chitosan concentration varied from 0 to 250mg/l. The results showed that chitosan is a promising corrosion inhibitor in sodium chloride medium. The inhibition efficiency at 30oC reaches 84.92% with a chitosan concentration of 250 mg/L.

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A New Corrosion Mechanism for X100 Pipeline Steel Under Oil-Covered Chloride Droplets

CORROSION ◽

10.5006/2804 ◽

2018 ◽

Vol 74 (9) ◽

pp. 947-957 ◽

Cited By ~ 4

Author(s):

Hongxing Liang ◽

Jing Liu ◽

Rebecca Filardo Schaller ◽

Edouard Asselin

Keyword(s):

Pipeline Steel ◽

Localized Corrosion ◽

Corrosion Mechanism ◽

General Corrosion ◽

Paraffin Oil ◽

Initial Stage ◽

X100 Pipeline Steel ◽

Corrosion Pits ◽

Stage 1 ◽

Two Stages

A 1.7 mM NaCl droplet on X100 pipeline steel covered by paraffin oil is used to simulate the corrosive environment encountered in heavy oil or bitumen pipelines. The development of corrosion under the droplet was monitored and explored in two stages. In the initial stage (1 h), the distribution of corrosion pits was heterogeneous with one area under the droplet presenting a higher pit density. As the corrosion proceeded (24 h), the localized corrosion in the area under the droplet with the higher pit density switched to general corrosion, while the other region of the droplet continued to pit. The mechanisms driving this new distinctive corrosion form developed beneath an underoil droplet are explained.

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Study on Corrosion Behavior of X80 Steel under Stripping Coating by Sulfate Reducing Bacteria

10.21203/rs.3.rs-68483/v1 ◽

2020 ◽

Author(s):

Yanyu Cui ◽

Yongxiang Qin ◽

Qingmiao Ding ◽

Yuning Gao

Keyword(s):

Electrochemical Impedance ◽

Pipeline Steel ◽

Sulfate Reducing Bacteria ◽

Fluorescent Labeling ◽

Corrosion Products ◽

Economic Losses ◽

Corrosion Mechanism ◽

Sulfate Reducing ◽

X80 Steel ◽

Reducing Bacteria

Abstract Background: At present, microorganism has been considered as important factors that threaten to buried pipelines with disbonded coatings. Aiming at the problem of unknown corrosion mechanism of sulfate-reducing bacteria (SRB), a series of studies have been carried out in this paper. Spectrophotometer and fluorescent labeling technology are used to study the growth and attachment of SRB in the simulated soil solution. The electrochemical behavior of X80 pipeline steel with or without SRB was researched by electrochemical methods such as open circuit potential, dynamic potential polarization curve, and electrochemical impedance spectroscopy. The microscopic morphology of the corrosion products on the surface of the sample was observed with a scanning electron microscope (SEM), and the element content of the corrosion products on the surface of the sample after corrosion was observed using X-ray energy spectrum (EDS) analysis. Results: The results showed that the growth and reproduction of SRB caused the pH of the soil simulated solution to increase, which promoted the corrosion of X80 steel. In addition, the cathode reaction of X80 steel in a sterile environment is the reduction of H+, and the main corrosion product is Fe oxides. When the soil simulation solution contains SRB, the cathodic reaction is controlled by both H+ reduction and sulfide depolarization reactions, and FeS appears in the corrosion products. Conclusion: Although the life cycle of SRB is only about 14 days, the corrosion of X80 steel is greatly promoted by SRB, and even causes corrosion perforation, which will bring huge economic losses and serious safety hazards.

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Electrochemical Behaviors of Ni-Base Superalloy CMSX-4 in 3.5 wt.% NaCl: Effect of Temperature and Preoxidation

Materials ◽

10.3390/ma13235478 ◽

2020 ◽

Vol 13 (23) ◽

pp. 5478

Author(s):

Xianzi Lv ◽

Quantong Jiang ◽

Jie Zhang ◽

Jianxin Zhang ◽

Zaiwang Huang ◽

...

Keyword(s):

Electrochemical Corrosion ◽

Effect Of Temperature ◽

Electrochemical Technique ◽

Corrosion Mechanism ◽

X Ray Diffraction ◽

Corrosion Morphology ◽

Electrochemical Behaviors ◽

Different Temperatures ◽

The Relationship ◽

Base Superalloy

The electrochemical behaviors of the Ni-base superalloy CMSX-4 were carried out in 3.5 wt.% NaCl solution using electrochemical technique. The electrochemical corrosion process was divided into four stages, and reactions at the alloy surface and corrosion morphology at each stage were analyzed. The passivity mechanism at the stable passivation stage and the occurrence of pitting corrosion at the transpassivation state were discussed especially. The corrosion parameters including Ecorr, Epass, ipass and Epit were compared at different temperatures to reveal the relationship between the temperature and the corrosion resistance properties. The corrosion products were investigated by the aid of X-Ray Diffraction (XRD) and Energy Dispersive Spectroscopy (EDS). By designing different preoxidation procedures, the corrosion mechanism of oxide scales was analyzed for the preoxidized samples.

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