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This paper seeks to describe the adoption and implementation of a cost‐effective gas pipeline corrosion monitoring and control procedure for use in natural gas infrastructural facilities in sub‐Saharan Africa.

The incidence and severity of pipeline corrosion in a major gas production facility were monitored using a combination of instrumented field survey (potential measurements, line currents and soil resistivity measurements) and microscopic evaluation (OM and SEM) techniques. Portable field survey equipment with appropriate circuitry, contactors and sensors for potential, line current and soil resistivity measurements were used to make the field measurements. The equipment was standardized and calibrated for use in the service environment. The field survey data were superimposed on common plots in order to obtain clearer and complementary information on possible corrosion hotspots and damage locations along the submerged pipelines. Metallographic examination of the samples collected from the field was carried out to establish the type of corrosion attacks and mode of failure of the pipeline material.

It was established that a combination of corrosion‐related damage occurred as a result of localized attack over time. The investigation procedure was cost‐effective and can be used to determine which pipeline structures are protected and to gauge with a high degree of precision the integrity of the submerged pipeline.

In the future, the procedure could be fully automated for routine on‐line/on‐site monitoring of gas pipelines in a sour‐gas environment.

The paper presents a useful database for the selection and/or design of corrosion‐resistant materials for use in sour‐gas environments and data for a comprehensive corrosion monitoring and control program in the peculiar service environment of sub‐Saharan Africa, for improved performance, productivity, personnel safety and reduced operating costs.

The information is useful to on‐site engineers and operators of gas‐production facilities, particularly in sub‐Saharan Africa, for designing and implementing cost‐effective corrosion monitoring and control programs.

Organic coatings are one of the most widely applied methods for corrosion protection of metallic materials such as the tubing used in sour gas field. However, such coatings usually encounter the risk of failure due to the harsh and complex environment. Therefore, the study of failure of the organic coating is highly significant.

In this paper, the effects of Cl-concentration, HCl content, hydrogen sulfide/carbon dioxide (H₂S/CO₂), temperature and flow rate on the failure of epoxy-phenolic coating on the internal surface of BG90S steel tubing were investigated using adhesion force measurement, metallographic microscope, electrochemistry impedance spectroscopy and Fourier transform infrared spectroscopy.

The results show that the Cl-concentration, HCl content and H₂S/CO₂ do not affect the failure process too much as the ion concentration increased. However, the flow rate at the high temperature is the most important factor affecting the corrosion resistance of the inner coating tubing. With the increase of the flow rate, the pore resistance of the coating shows a decreasing trend, and the rate of decrease in pore resistance is first rapid and then slow. It demonstrates that the penetration speed of the electrolyte solution into the coating varied from fast to slowly. A weakening influence of the flow rate on the penetration failure of the inner coating can be found as the increase of the flow rate. Once the HS-ions penetrate through the coating and reach at the coating/steel interface where H₂ could be formed through the adsorption reaction, the coating failure occurs.

The failure of the coating depends on the penetration rate of water and ions, with the presence of exposed or punctured holes is accelerated and HS- was adsorpted by substrate Fe, and form H2 molecules between the coatings and substrate, that results failure of coatings.

The purpose of this investigation was to research the corrosion behavior of welded joints of bimetallic composite tube (X65/316L) welded with Inconel 625 in simulated sea water and in simulated production water, respectively.

The different electrochemical corrosion and galvanic corrosion behaviors of different welded zones were identified using the dynamic potential scan method and galvanic corrosion technique.

The heat-affected zone (HAZ) of welded joints was the most critical zone for corrosion. The closer to the welding line, more severe was the corrosion that was evident in the HAZ at room temperature. In welded joints of X65 tested in simulated seawater, tremendous corrosion occurred in the HAZ, followed by the base metal, and finally the welding line. However, there were few differences in corrosion of the different zones of welded joints in 316L in simulated production water. In such joints of 316L, corrosion comparatively attacked more easily to the HAZ. In galvanic corrosion tests, tremendous galvanic corrosion was evident on welded joints on X65, but comparatively slight gavanic corrosion appeared at welded joints in 316L. With the increased temperature, galvanic corrosion of welded joints was enhanced.

The results can provide reference for reducing the gavalic corrosion of welded bimetallic composite tube metal in the actual operation.

The present work primarily aims to study the corrosion characterization of tubular steel API‐P110 in high H₂S containing solution with or without CO₂.

Corrosion behaviors of steel in buffered solutions containing 50 percent H₂S and various levels of CO₂ concentration were investigated via weight‐loss method, SEM and EDS. The effects of CO₂ on corrosion occurred on the metal were analyzed by electrochemical techniques.

Corrosion rates of steel decreased as the CO₂ content in H₂S/CO₂ solution increased. It was observed for the tubular steel to experience an increase in corrosion rate at concentrations 17 percent CO₂ or 34 percent CO₂ in 50 percent H₂S while when further increasing concentration of CO₂ to 50 percent the corrosion rate decreases. Increased CO₂ content in H₂S/CO₂ led to fewer anions desorbing and fewer reactants adsorbing, e.g. H+, H₂CO₃. As a result, cathodic reaction rate decreased and the amount of hydrogen absorbed decreased.

The experimental results showed that corrosion alleviated when increasing CO₂ content in high H₂S and CO₂ containing environment.

Salt Spray Cabinets. A whole new range of Salt Spray cabinets and Sulphur Dioxide cabinets are available from John Godrich, Consulting Engineers. These include the standard but improved STR range of chest‐type Salt Spray cabinets in 400 or 1000 litre capacity but an addition to these is the new STK range which can carry out sulphur dioxide testing as well to conform to the DIN, BS and Kesternich standard test. This is now a feature of all the Liebisch Salt Spray cabinets and indeed on the cabinet type (front opening door) these can now be produced with a micro‐processor programmer to give common salt, acetic acid and sulphur dioxide testing all within one cabinet, which is fully programmable and has an automatic changing system from one test to another without operator assistance. Another addition to the range is the SL‐2000 front opening cabinet of 2000 litre capacity having a length of approximately 2 metres, a height of just over 1 metre and a depth of .89 metre. This is useful for testing the longer type sample and again can have the features mentioned above for sulphur dioxide and automatic change over systems.

This paper aims to clarify the corrosion behavior of two famous structural steels in sour environment. These steels have a vast application in oil and gas industries. The study aims to find the effect of different concentrations of sour solution on the origin of crack in these steels.

After preparation of specimens, different sour solutions were made using the synthetic brine (according to National Association of Corrosion Engineers [NACE], Technical Committee Report 1D182) and various amounts of Na₂S.9H₂O and CH₃COOH. The polarization test was done by Potansiostat apparatus model Zahner-IM6 at two temperatures, 25°C and 50°C. The corrosion current densities were obtained from the polarization curves. Finally, the corrosion products and hydrogen-induced cracking (HIC) were investigated by Tescan Vega II XMU scanning electron microscope (SEM) linked to a Rontec energy-dispersive X-ray spectroscopy (EDS) system.

API 5L-X70 steel showed smaller corrosion current values than A516-Gr70 steel. The HIC cracks propagated parallel to the surface of A516-Gr70 steel in three solutions and confirmed the inappropriateness of this steel for sour environment applications.

This paper studies the effect of sour environment on the behavior of two famous industrial steels at two temperatures by new method.

The purpose of this paper is to solve the tubing corrosion problem of B Block on the Right Bank of Amu Darya river sour gas field.

By using four-point-bending method, the tubing’s ability to resist sulfide-stress cracking was tested. Simulating the wellbore corrosive environment, the corrosion inhibitor which was suitable for gas filed had been screened. According to the characteristic of Amu Darya river gas field, the corrosion monitor system had been designed.

From the feedback of wellbore corrosion monitor result, the corrosion rate was lower than 0.076 mm/a.

This anti-corrosion technique provides security for the development of gas field.

The purpose of this paper is to investigate stress corrosion cracking (SCC) for 304, 316, and 321 stainless steels in petroleum‐processing environments.

Sensitized austenitic stainless steels were subjected to a microstructure investigation and electrochemical test. Stressed sensitized 304, 316, and 321 stainless steels were selected and subjected to various environments that included polythionic acid, sour solution, and chloride solution that were prepared in the laboratory to simulate service environments in the petroleum refinery.

Microstructure investigation reveals more severe SCC in polythionic acid than in the sour and chloride solutions. Type 321 SS gives better resistance to SCC than do 304 and 316 SS in the three solutions. It is concluded that acidity of solutions has a relatively minor influence in promoting cracking. However, polythionic acid is found to be the primary causative agent.

The results demonstrated that SCC is more severe in polythionic acid than in chloride and sour solutions.

Important reserves of oil and gas, which are left to be discovered and produced, are mainly concentrated in challenging locations and under severe conditions such as high pressure (HP)/high temperature (HT). The presence of aggressive environments including H₂S, CO₂ and chlorides plus HP/HT causes a series of corrosion problems, which cost the oil industry billions of dollars a year. Thus, there is an increasing challenge for tubes (i.e. oil country tubular goods, for short, OCTG) used in producing oil and gas. The purpose of this study is to summarize different kinds of corrosion problems and their mitigation, to more efficiently protect OCTG from corrosion.

To effectively select proper mitigation methods, the mechanism of corrosion must be understood, which can be classified into four categories: sweet corrosion, sour corrosion, galvanic corrosion and microbiologically induced corrosion. Also, the effects of environmental and material factors on the corrosion rate are presented. Subsequently, current technology of mitigating these corrosion problems has been discussed, including the development of materials, application of chemical inhibitors and application of protective layers.

It is stressed that limits exist for each individual mitigation method; therefore, a careful balance between economic life of OCTG and safety in operation is required.

The main purpose of this essay is to give a brief review and detailed introduction and analysis about those technologies.

Bimetallic composite pipe consists of a corrosion resistance alloy (CRA) layer for corrosion resistance and carbon steel for mechanical properties, which shows a promising prospect of gathering pipeline with its effective-cost and reliable corrosion resistance. However, the corrosion resistance of composite pipe is determined by the quality of its welding gap. This paper aims to investigate the TIG welding gap corrosion resistance of X52/825 metallurgical clad pipe in H₂S/CO₂ environment.

Corrosion tests of X52/825 welding gap were performed in a stimulated gas field solution containing both 1 MPa CO₂ and 1.5 MPa H₂S at 70°C for 720 h in a self-designed high temperature and high pressure autoclave. The anti-stress corrosion cracking (SCC) performance of X52/825 clad pipe ring root welding gap was investigated in both NACE A solution and the stimulant gas field solution by four point bending testing and constant load test. Then the experiments were rerun in XX high sour gas well. In addition, the alloy diffusion and microstructure characteristics of TIG welding gap were analyzed through scanning electron microscopy and energy dispersive X-ray spectroscopy technologies.

The results reveal that the root welding gap is almost not corroded in the stimulant gas field solution, and no micro-cracks were observed by electron microscope. Anti-SCC test results show the root welding gap does not break, indicating a good resistance to environmental-cracking in H₂S/CO₂ environment. The transition layer can be obviously observed in the root welding zone, and the alloy content of transition layer is diluted. However, the transition layer does not penetrate into the inner of CRA layer, which illustrates its good anti-corrosion performance. Therefore, TIG welding technology can be well used in the welding process of composite pipe.

This paper may provide theoretical reference for manufacturing and application of clad pipe.