scholarly journals An Investigation of Internal Corrosion of Oil and Gas Transporting Carbon Steel Pipes in the Niger Delta Area of Nigeria

2017 ◽  
Vol 2 (8) ◽  
pp. 22
Author(s):  
Obotowo W. Obot ◽  
Charles N. Anyakwo
Keyword(s):  
Carbon Steel ◽  
Niger Delta ◽  
Oil And Gas ◽  
Co2 Corrosion ◽  
Corrosion Monitoring ◽  
Temperature Oxidation ◽  
Internal Corrosion ◽  
Delta Area ◽  
Steel Pipes ◽  
Corrosion Mechanisms

Internal corrosion of carbon steel pipes of oil and gas Companies in the Niger Delta area of Nigeria using coupons and ER probes is presented. Corrosion mechanisms for the lines vary with the fluid type and operational parameters. Aqueous corrosion with, in some cases CO2 corrosion additive, erosion corrosion and elevated temperature oxidation are corrosion mechanisms implicated in the pipes. No H2S-induced corrosion was observed for all the lines investigated. They act separately or synergistically to exacerbate the corrosion attack.  Application of inhibitors of the amine group drastically lowered the corrosion rates. Effective inhibition regime had in an instance markedly lowered the corrosion rate of a line from 42.7080mpy to 1.3447mpy. The ER probes incorporation offered a comparative corrosion monitoring alternative and provided insight into the real time conditions of the lines over prolonged periods of times. The exercise proved very useful in determining the corrosion status of the pipes and helped to determine the lines that should require immediate maintenance intervention to obviate possible ugly incidents of breakouts and ruptures.

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.

ANALYSIS OF THE USE OF ULTRASONIC TESTING METHODS IN THE FRAMEWORK OF CORROSION MONITORING OF INTERNAL CORROSION AT GAS PRODUCTION FACILITIES IN THE PRESENCE OF CARBON DIOXIDE

2020 ◽  
pp. 30-35
Author(s):  
D. N. Zapevalov ◽  
R. K. Vagapov
Keyword(s):  
Carbon Dioxide ◽  
Oil And Gas ◽  
Thickness Measurement ◽  
Gas Production ◽  
Corrosion Monitoring ◽  
Internal Corrosion ◽  
Ultrasonic Methods ◽  
Ultrasonic Thickness Measurement ◽  
Gas Fields ◽  
Production Facilities

The use of various intrusive and non-intrusive methods of corrosion monitoring makes it possible to assess the corrosion situation and the effectiveness of the applied corrosion protection agents in conditions of internal corrosion at gas production facilities due to the presence of aggressive gases. The analysis of the application of ultrasonic testing methods as part of corrosion monitoring of internal corrosion at gas production facilities in the presence of corrosive components is carried out. Ultrasonic thickness measurement is widely used as a non-intrusive method for monitoring internal corrosion and detecting corrosion defects in promising gas fields. Many gas fields (Bovanenkovskoye oil and gas condensate field, Urengoy oil and gas field and others) revealed corrosion defects due to cases of internal corrosion due to the presence of increased amounts of carbon dioxide in the produced hydrocarbons. Under conditions of corrosion in the presence of carbon dioxide, ultrasonic methods for measuring the thickness of a metal have certain limitations associated with the unpredictable local nature of carbon dioxide corrosion, which should be considered when used in gas facilities. The main method for measuring thickness under operational conditions is ultrasonic thickness measurement, which is used in conjunction with radiographic monitoring. Using these two main non-intrusive methods, corrosion monitoring monitors the thinning of the metal, the size and depth of local defects and the dynamics of their change over time. Based on the results of measuring the residual wall thickness of the pipe and equipment, the possibility of their further work is determined, and recommendations are made on extending the safe life of gas facilities. The authors analyzed the literature data on new options and technical solutions for the use of ultrasonic methods in the measurement of the thickness of a metal surface.

Flow Assurance of Wet Gas Pipelines From a Corrosion Viewpoint

2002 ◽  
Author(s):  
Rolf Nyborg ◽  
Arne Dugstad
Keyword(s):  
Carbon Steel ◽  
Oil And Gas ◽  
Prediction Models ◽  
Process Equipment ◽  
Corrosion Control ◽  
Internal Corrosion ◽  
Application Range ◽  
Wet Gas ◽  
Offshore Oil And Gas ◽  
Stabilization Technique

In many offshore oil and gas projects under development, the pipeline costs are a considerable part of the investment and can become prohibitively high if the corrosivity of the fluid necessitates the use of corrosion resistant alloys instead of carbon steel. Development of more robust and reliable methods for internal corrosion control can increase the application range of carbon steel and therefore have a large economic impact. Corrosion control of carbon steel pipelines has traditionally often been managed by the use of corrosion inhibitors. The pH stabilization technique has been successfully used for corrosion control of several large wet gas condensate pipelines in the last few years. Precipitation of scale and salts in the pipeline and process equipment creates further challenges when formation water is produced. Different corrosion prediction models are used in the industry to assess the corrosivity of the transported fluid. An overview of the present models is given together with a link to fluid flow modeling.

Role of Asphaltenes in Inhibiting Corrosion and Altering the Wettability of the Steel Surface

CORROSION ◽  
2011 ◽  
Vol 67 (10) ◽  
pp. 105006-105006-11 ◽  
Author(s):  
P. Ajmera ◽  
W. Robbins ◽  
S. Richter ◽  
S. Nešić
Keyword(s):  
Carbon Steel ◽  
Steel Surface ◽  
Protective Layer ◽  
Contact Angles ◽  
Co2 Corrosion ◽  
Water Contact ◽  
Internal Corrosion ◽  
Corrosion Rates ◽  
Mechanism Of Inhibition ◽  
Carbon Dioxide Co2

Abstract Asphaltenes (heptane insolubles) from a variety of crude oils have been identified previously as contributors to inhibition of internal corrosion of mild steel pipelines. However, the mechanism of inhibition is unknown. To explore the mechanism, carbon dioxide (CO2) corrosion rates and wettability (oil/water contact angles) have been measured using Arab Heavy crude oil and its asphaltenes. Inhibition of CO2 corrosion rates for carbon steel was measured using electrochemical methods in a glass cell; wettability was assessed using contact angle measurements in a multiphase goniometer. The phase behavior of asphaltenes in corrosion and wetting was evaluated in the crude, toluene (C7H8), or heptol (70:30 mixture of heptane [C7H16] and toluene). Inhibition on steel exposed to a hydrocarbon phase increased with the concentration of asphaltenes in toluene. Inhibition by asphaltenes dissolved in toluene appears to be more effective than in the whole crude, at equivalent concentrations of asphaltenes. At 5 wt% in toluene, asphaltenes form a strong protective layer on the carbon steel surface, which reduces the corrosion rate and makes the surface hydrophobic. When the solubility of the oil is altered to the point where asphaltenes start to flocculate, it enhances the corrosion inhibition greatly. However, the inhibition is not as persistent as for the fully dissolved asphaltenes, and the surface needs to be periodically wetted with the oil phase to maintain the protection.

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.

Velocity Guidelines for Avoiding Erosion-Corrosion Damage in Sweet Production With Sand

1998 ◽  
Vol 120 (1) ◽  
pp. 78-83 ◽  
Author(s):  
J. R. Shadley ◽  
E. F. Rybicki ◽  
S. A. Shirazi ◽  
E. Dayalan
Keyword(s):  
Carbon Steel ◽  
Oil And Gas ◽  
Corrosion Damage ◽  
Gas Production ◽  
Metal Loss ◽  
Co2 Corrosion ◽  
Oil And Gas Production ◽  
Erosion Corrosion ◽  
Steel Piping ◽  
Loss Rates

CO2 corrosion in carbon steel piping systems can be severe depending on a number of factors including CO2 content, water chemistry, temperature, and percent water cut. For many oil and gas production conditions, corrosion products can form a protective scale on interior surfaces of the piping. In these situations, metal loss rates can reduce to below design allowances. But, if sand is entrained in the flow, sand particles impinging on pipe surfaces can remove the scale or prevent it from forming at localized areas of particle impingement. This process is referred to as “erosion-corrosion” and can lead to high metal loss rates. In some cases, penetration rates can be extremely high due to pitting. This paper combines laboratory test data on erosion-corrosion with an erosion prediction computational model to compute flow velocity limits (“threshold velocities”) for avoiding erosion-corrosion in carbon steel piping. Also discussed is how threshold velocities can be shifted upward by using a corrosion inhibitor.

scholarly journals Corrosion Investigation of Commercially Available Linepipe Steel in CO2 Environment

2018 ◽  
Vol 7 (3.32) ◽  
pp. 15
Author(s):  
Muhammad Haris ◽  
Saeid Kakooei ◽  
Mokhtar Che Ismail
Keyword(s):  
Carbon Steel ◽  
Corrosion Rate ◽  
Oil And Gas ◽  
Corrosion Behaviour ◽  
Complex Problem ◽  
Gas Production ◽  
Co2 Corrosion ◽  
Oil And Gas Production ◽  
The Difference ◽  
Co2 Environment

CO2 corrosion has been the most prevalent form of corrosion and is considered as a complex problem in oil and gas production industries. The CO2 in presence of water causes sweet corrosion that is responsible for failure of pipeline during transportation of Oil and Gas. This work studies the corrosion behaviour of carbon steel specimens in CO2 environment at different temperatures but at constant pressure. The effect of CO2 on Carbon Steel specimens (X65, A106) were studied in simulated solution of 3 wt.% NaCl. The specimens were immersed into the CO2 containing solution for 48 hours and corrosion behaviour was investigated by using electrochemical test like Linear Polarization Resistance and Tafel plot. The results indicate that the temperature has an important effect of corrosion rate of carbon Steel in CO2 environment. Corrosion rate of 1.5-2 mm/yr was reported for both steels at lower temperature while at higher temperature the difference can be observed due to difference in protective nature of steels. Similar Corrosion rate around 1.5 -2 mm/yr was observed at 25°C for both A106 and X65 while at 50°C and 75°C the corrosion rate varies significantly 1.5-3 mm/yr and 3.5-6 mm/yr.  

Assessment of Piping Field Failures and Burst Tests on Carbon Steel Pipes With Local Wall Thinning Using ASME Section XI Code Case N-597-2

2009 ◽  
Author(s):  
Kunio Hasegawa ◽  
Toshiyuki Meshii ◽  
Douglas A. Scarth
Keyword(s):  
Carbon Steel ◽  
Accelerated Corrosion ◽  
Steel Pipes ◽  
Pipe Burst ◽  
Evaluation Procedures ◽  
Wall Thinning ◽  
American Society ◽  
Corrosion Mechanisms ◽  
Flow Accelerated Corrosion ◽  
Local Wall Thinning

One of the more common modes of degradation in power plant piping has been wall thinning due to erosion-corrosion or flow-accelerated corrosion. Extensive work has been performed to understand flow-accelerated corrosion mechanisms and develop fracture criteria of locally thinned pipes, since the tragic events at Surry Unit 2 and Mihama Unit 3. A large number of tests have been performed on carbon steel pipes, elbows and tees with local wall thinning. In addition, the American Society of Mechanical Engineers Boiler and Pressure Vessel Code provides procedures in Code Case N-597-2 for evaluation of wall thinning in pipes. This paper provides validation of the evaluation procedures in Code Case N-597-2 by comparing with the field rupture data and pipe burst test data. The allowable wall thinning from the Code Case N-597-2 procedures is shown to maintain adequate margins against rupture.

scholarly journals Corrosion Rate of Carbon Steel A106 Gr B in Amine-CO2 Contained Solutions

2021 ◽  
Vol 3 (1) ◽  
pp. 1-8
Author(s):  
Yuli Asmara ◽  
Tedi Kurniawan ◽  
Kushendarsyah Saptaji
Keyword(s):  
Carbon Steel ◽  
Corrosion Rate ◽  
Oil And Gas ◽  
Caustic Solution ◽  
Co2 Corrosion ◽  
Co2 Gas ◽  
Linear Polarization Resistance ◽  
Reduce Risk ◽  
Carbon Dioxide Co2 ◽  
Static Conditions

Carbon dioxide (CO2) is one of the corrosive element which exists in oil and gas industries. To prevent CO2 corrosion on carbon steel pipelines, amine-base solvent and caustic solutions are commonly applied. Accordingly, effectiveness of amine base solvent and caustic solutions to reduce risk of corrosion becomes key parameters in determining service lifetime of pipelines made of carbon steel. In this research, the corrosion rate of carbon steel A106 Gr B in amine solutions combined with saturated CO2 gas and caustic solution was studied. The experiments were carried out in static conditions and the Linear Polarization Resistance (LPR) technique was used to measure the corrosion rate (as per ASTM G 5-94). It was found that the corrosion rate in the amine-based solution had shown remarkable results. Somehow, the corrosion rate in an amine-based solvent containing saturated CO2 gas has increased to 200%. The temperature increment to 50°C from room temperature has also increased the corrosion rate. Meanwhile, the caustic addition in amine solution has reduced the corrosion rate of carbon steel.

Assessment of Piping Field Failures and Burst Tests on Carbon Steel Pipes With Local Wall Thinning Using ASME Section XI Code Case N-597-2

2011 ◽  
Vol 133 (3) ◽  
Author(s):  
Kunio Hasegawa ◽  
Toshiyuki Meshii ◽  
Douglas A. Scarth
Keyword(s):  
Carbon Steel ◽  
Accelerated Corrosion ◽  
Steel Pipes ◽  
Pipe Burst ◽  
Evaluation Procedures ◽  
Wall Thinning ◽  
American Society ◽  
Corrosion Mechanisms ◽  
Flow Accelerated Corrosion ◽  
Local Wall Thinning

One of the more common modes of degradation in power plant piping has been wall thinning due to erosion-corrosion or flow-accelerated corrosion. Extensive work has been performed to understand flow-accelerated corrosion mechanisms and develop fracture criteria of locally thinned pipes since the tragic events at Surry Unit 2 and Mihama Unit 3. A large number of tests have been performed on carbon steel pipes, elbows, and tees with local wall thinning. In addition, the American Society of Mechanical Engineers Boiler and Pressure Vessel Code provides procedures in Code Case N-597-2 for the evaluation of wall thinning in pipes. This paper provides validation of the evaluation procedures in Code Case N-597-2 by comparing with the field rupture data and pipe burst test data. The allowable wall thinning from the Code Case N-597-2 procedures is shown to maintain adequate margins against rupture.

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