On the Dependence of Steel Corrosion in Oxygen-Free Aqueous Media on pH and the Pressure of CO2

A mechanism for carbon dioxide corrosion in oxygen-free aqueous oil and gas field media was proposed. Variations in the corrosion rate of low-carbon steel and the pH of a model 3% NaCl solution with the partial pressure of CO₂ (from 0.7 to 1.0 MPa), temperature (20 to 80°C), and time were analyzed. With a simple model system, it was shown that the De Waard–Milliams, Crolet, and Kuznetsov equations can be used to predict the corrosion rate of steel from the partial pressure of CO₂ and the pH.     

Entwicklung,Standardisierung und Korrelierung von Meßmethoden zur Bestimmung der Inhibitorwirksamkeit in H2S/CO2-haltigem Rohöl und Erdgas

Development, standardization and correlation of measurement methods to determine the effectiveness of corrosion inhibitors used in H₂S/CO₂ containing crude oil and natural gas The object of the research project was to simulate as closely as possible actual production conditions for crude oil and natural gas and in this manner 1. to test the meaningfulness of various test methods (stirred autoclave tests with rotating specimens, high pressure flow loop), 2. to develop a test method which allows a precise selection of inhibitors for corrosion protection, 3. to examine the usefulness of simple test methods as screening tests. By this means a more economic selection of inhibitors and materials for use in the field should be made possible. The results of the research program show that the proposed equipment options allow testing which correlates with actual practice. The autoclave method with rotating specimens allow parameter studies, i.e. the effects of the test parameters (temperature, H₂S/CO₂ ratio, flow) were correctly reproduced. The advantage of the flow loop is the better simulation of the flow conditions. The sequence of the inhibitor tests could be chosen such that a parameter study is first carried out at relatively low cost using the stirred autoclaves and the corrosion rates of the tubings and pipelines are then determined by targeted tests in the high pressure flow loop.     

一种海底管道多相流内腐蚀直接评价的方法

提出了一种适用于海上油田海底管道多相流内腐蚀直接评价(ICDA)方法;基于海底管道基础数据、生产工况以及油气水检测数据,对介质流态的热力学、动力学和水力学影响因子进行分析,评估海管内腐蚀发生的位置及最大局部腐蚀速率;将南海多条海管的直接检测数据与ICDA结果进行对比。结果表明:ICDA评估方法能够准确地反映海管实际内腐蚀状况,为不能采用智能通球FML内检测的海管提供了一种有效的内腐蚀评估方法。     

X65钢海底管道在CO2/H2S腐蚀环境下的适用性

利用高温高压反应釜模拟试验和电化学测试,研究了X65钢海底管道在CO2/H2S环境下的耐蚀性。结果表明,不加缓蚀剂条件下,X65钢在总压为0.25MPa时的平均腐蚀速率及局部腐蚀风险与总压为0.7MPa时相比,均显著降低。添加100mg/L的缓蚀剂,X65钢的腐蚀速率显著降低,缓蚀效果较好;电化学测试与模拟试验结果一致。降压至0.25MPa分离出部分腐蚀性气体后再输送可大大降低内腐蚀风险,结合缓蚀剂措施,该腐蚀环境下可选择X65钢海底管道输送油气。     

Effect of O2 on down-hole corrosion during air-assisted steam injection for heavy oil recovery

ABSTRACT

Air-assisted steam injection is used to enhance hydrocarbon recovery from heavy oil reservoirs. During this process, downhole tubular goods are subject to corrosion in a mixed oxygen-carbon dioxide-steam environment at temperature up to around 200°C causing a low-temperature oxidation phenomenon. Here we investigate the influence of the O₂/CO₂ ratio on the corrosion of P110 steel, a grade that is commonly used for oil well casings. Our findings show that corrosion is greatly influenced by the O₂ pressure but hardly at all by the CO₂ pressure. The maximum corrosion rate was in excess of 65?mm per year. However, alkalisation of the injected fluid, which promoted the formation of a protective magnetite scale, was found to greatly reduce corrosion.     

Autoklaven-Untersuchungen der Spannungsrißkorrosion von Fe-Cr-Ni-Legierungen in NaCl/Co2/H2S-Medien

Autoclave investigation of stress corrosion cracking behaviour of Fe-Cr-Ni alloys in NaCl/CO₂/H₂S-environment In oil and gas production, the corrosion problems increase as the depth of the reservoirs increases. The oil and gas products contain chloride-rich waters and mixtures of H₂S and CO₂ at high pressures and temperatures. Materials that can be used under these conditions are only high strength high alloy steels and nickel base alloys. These materials must be assessed for corrosion resistance under these conditions. The environment contain chloride ions and hydrogen sulphide, which are known to be critical components for SCC. With the aid of autoclave experiments, the fields of corrosion resistance for the materials no. 1.4462, 1.4563 and 2.4618 were determined as a function of temperature and hydrogen sulphide pressure. The base environment was a 5 Molar sodium chloride solution at 20 bar carbon dioxide. While the corrosion resistance of the duplex steel, material no. 1.4462, decreases markedly as the strength of the material and the hydrogen sulphide pressure increase, the two austenitic materials are completely resistant up to 300 °C and hydrogen sulphide pressure of 15 bar. Only at 300 °C and high partial pressures of hydrogen sulphide the material no. 1.4563 did fail, when stressed to stress levels higher than the YS. The crack path was predominantly transgranular with minute fractions of intergranular cracking. The microstructure appears to have no effect. All results indicate that a mixed mechanism of hydrogen- and chloride induced SCC is operting, while a corrosion enhancement due to interaction of both critical components takes place.     

Effect of hot corrosion on the creep properties of types 321 and 347 stainless steels

Problems caused by hot corrosion and creep damage on superheater and reheater tubes of power plants using heavy oil as fuel inhibit the continuous service of the boilers and shorten their design lives. The acceleration of hot corrosion attack of boilers is caused by the presence of fuel ash deposits containing V, Na, and S, in the form of Na₂SO₄ and V₂O₅, which form low melting point phases. In addition to this, the tubes are exposed to the action of both high stresses and high temperatures, producing a continuous plastic deformation of the tube walls called creep damage. Creep rupture tests were carried out in the temperature range 620 to 670 °C in static air in the presence of corrosive environments using 321H and 347H type stainless steels used in superheater and reheater tubes under hot corrosion and creep environments. The corrosive environment includes synthetic Na₂SO₄, V₂O₅, and the mixture 80% V₂O₅-20%Na₂SO₄. Also, the role of the different elements present in the environments on corrosion was investigated using electronic microscopy and x-ray diffraction techniques.     

On the Dependence of Steel Corrosion in Oxygen-Free Aqueous Media on pH and the Pressure of CO2

A mechanism for carbon dioxide corrosion in oxygen-free aqueous oil and gas field media was proposed. Variations in the corrosion rate of low-carbon steel and the pH of a model 3% NaCl solution with the partial pressure of CO₂ (from 0.7 to 1.0 MPa), temperature (20 to 80°C), and time were analyzed. With a simple model system, it was shown that the De Waard–Milliams, Crolet, and Kuznetsov equations can be used to predict the corrosion rate of steel from the partial pressure of CO₂ and the pH.     

High-temperature degradation and protection of ferritic and austenitic steels in steam generators

The useful life of superheaters and reheaters of power stations which use heavy fuel oil is shortened and their continuous service is inhibited by corrosion (fireside) and creep-type problems. The increase of corrosion attack on boilers is caused by the presence of fuel ash deposits containing mainly vanadium, sodium, and sulfur which form low-melting-point compounds. The tubes are exposed to the action of high stresses and high temperatures, producing the so-called “creep damage.” In this work, two kinds of results are reported: lab and field studies using a 2.25Cr-1Mo steel. The laboratory work was in turn divided into two parts. In the first, the steel was exposed to the action of natural ash deposits in oxidant atmospheres at 600 ° for 24 h. In the second part, tensile specimens were creep tested in Na₂SO₄, V₂O₅, and their mixture over a temperature range of 580 to 620 °. In the field work, components of a power station were coated with different types of nickel-and iron-base coatings containing chromium, Fe-Cr, and Fe-Si using the powder flame spraying technique. After testing, the coated tubes were analyzed using electron microscopy. The results showed that all the coating systems had good corrosion resistance, especially those containing silicon or chromium.     

Characterisation of CO2 corrosion scale in simulated solution with Cl– ion under turbulent flow conditions

Abstract

In the present work, characterisations such as surface morphology, cross-section image and composition of corrosion scale formed on the P110 steel under turbulent flow conditions with various Cl^– concentrations have been studied by means of scanning electron microscopy, X-ray diffraction and X-ray photoelectron spectroscopy. The corrosion medium was the simulated solution of one oil/gas field, saturated with CO₂ at 100°C and 4 MPa. The tests were conducted corresponding to various Cl^– concentrations and varied flow velocities. It is concluded that Cl^– concentration and flow velocity have an important effect on the corrosion scales formed on the samples. In addition, the protective properties and adherence of the corrosion scales were characterised by the analysis of the scale formation and influence mechanisms associated with Cl^– concentration and flow velocity. Moreover, a lattice model is created to interpret and illuminate the corrosion process.     

不同材质油套管钢的CO2腐蚀行为

目的不同管材的CO_2腐蚀行为存在差异,为优选经济型抗CO_2腐蚀材质油套管,探究不同腐蚀条件下常规管材的CO_2腐蚀特征。方法以实际油田的地层水样为腐蚀介质,在高温高压的条件下,对不同材质的油套管进行模拟实验。利用X射线衍射仪(XRD)分析腐蚀试样表面腐蚀产物的形貌特征,研究CO_2分压、温度、测试时间对油套管腐蚀速率的影响规律。结果随着CO_2分压的增加,普通碳钢和低Cr钢的腐蚀速率显著变化,当CO_2分压为0.3 MPa时,普通碳钢腐蚀速率为2.2021 mm/a,而13Cr的腐蚀速率很低,仅为0.1052 mm/a,未表现出明显的规律;腐蚀速率随着温度的升高呈先增加后降低的变化规律,N80,1Cr钢的腐蚀速率远高于13Cr钢;在较短的测试周期内,N80,1Cr,3Cr油套管钢的腐蚀速率略有增加,随着测试周期持续增加,油套管钢的腐蚀速率明显下降;从腐蚀形貌来看,普通碳钢试样的腐蚀程度严重,以均匀腐蚀为主,1Cr,3Cr钢表面存在少量的局部浅斑,以局部腐蚀为主;13Cr材质钢的表面平整,有光泽且无点蚀,腐蚀程度轻微。结论普通碳钢的腐蚀速率对CO_2分压的影响比含Cr合金材质钢更敏感,温度和测试周期均对金属表面的腐蚀产物产生影响,随着温度和测试周期的持续增加,金属表面形成Fe CO3保护膜,含Cr钢表面因铬的富集形成钝化膜,抑制油套管的腐蚀速率,研究成果对CO_2腐蚀环境中的油套管选材具有理论指导意义。     

Evaluation of corrosion resistance of two engineering alloys in molten salts by electrochemical techniques

The electrochemical behaviour of two steels typically used in power boilers has been studied in the temperature range from 540°C to 680°C. Two environments were used: a) a synthetic salt mixture of 80% V₂O₅ ? 20% Na₂SO₄ and b) oil ash collected from a high temperature reheater. Corrosion rates obtained from electrochemical potentiodynamic polarisation curves (Tafel extrapolation) were compared for both steels exposed in each environment. The results showed that increases in temperature resulted in higher corrosion rates, being this effect most notorious above about 620°C. In the synthetic salt, and at temperatures up to about 580°C, both steels showed similar behaviour. With further increases in temperature, the T22 steel was less resistant and, at the highest temperature used here, its corrosion rate was almost seven times higher than that measured for the 347H steel. The results obtained with the natural oil ash for the T22 steel showed a dramatic increase in corrosion rate as temperature goes up over the range used. For the 347H steel, and up to about 580°C, the corrosion rates were similar to those obtained with the synthetic salt. Above 580°C, the corrosion rate measured increased slightly with temperature, being at 680°C about 2.5 times higher than that found by using the synthetic salt. Therefore, an important difference in corrosion rates has been found depending upon the corrosive salt used. This is an important result because imply that, at least for materials used in fossil power plants, more realistic data can be obtained by using natural ashes in the experimental work.     

油气开采环境下管道的协同腐蚀及防护研究进展*

服役于高温高压 CO₂ / H₂S 环境下的管道腐蚀是油气田中急需解决的重要问题。CO₂、H₂S 及 Cl^- 是油气田管道中常见的腐蚀介质，其与温度、压力、pH值、含水率、流速等外界因素间的协同腐蚀作用会导致管道严重腐蚀，研究这些腐蚀介质与外界因素的协同腐蚀机制以及减缓管道腐蚀的措施有着重要的科学意义和经济价值。针对油气开采过程中金属管道的腐蚀问题，综述了 CO₂、H₂S 及 Cl^- 在协同腐蚀过程中起到的作用，讨论了温度、压力、pH 值、含水率及流速等实际工况条件下外界因素对腐蚀过程的影响。论述了现有管道腐蚀防护技术与工艺的特点：合金元素的掺杂可以改善腐蚀形貌，提高腐蚀产物层的致密性，等离子体扩渗与镀膜技术能够制备一层致密的保护层来吸收部分腐蚀介质并减缓腐蚀速率，缓蚀剂的添加可以减缓管道的阴极或阳极反应或形成减缓腐蚀速率的吸附层。最后展望了未来油气田管道防护技术的发展方向：为了有效地对油气开采环境下的管道进行保护，需要进一步研究腐蚀介质和外界因素间的协同腐蚀作用，模拟实际工况下的腐蚀环境， 对等离子体扩渗与镀膜技术、缓蚀剂等现有的防护技术进行系统的试验测试。     

N80钢在二氧化碳饱和的模拟油田液中的高温高压腐蚀行为研究

        用失重法研究了高温高压下N80钢在模拟油田液中的腐蚀行为.结果表明： 随着温度及CO₂分压的升高,N80钢的腐蚀速率增大,并在5 MPa及100℃时达到最大值.在此基础上,考察了Cl^-对腐蚀速率的影响.     

The Inhibitory Effect of Magnesium Sulfonate as a Fuel Additive on Hot Corrosion of Generating Tubes of Power Plant Boiler

Changing the power plant boiler fuel from natural gas into fuel oil during the cold months of the year causes hot corrosion in generating tubes. Visual observations, thickness and thermocouple measurements and ash analysis proved the hot corrosion by displaying the sticky melted ash, thickness reduction, surface temperature of tubes at about 600 °C and existence of complex corrosive elements such as sodium and vanadium, respectively. Therefore, based on the experimental data from the power plant, laboratory studies were performed to survey the corrosion inhibition effect of magnesium sulfonate as an easy to use fuel additive. A low carbon steel, 70 wt%Na₂SO₄–25 wt%V₂O₅–5 wt%NaCl and mineral part of magnesium sulfonate ash were used as the generating tube material, corrosive and additive ashes, respectively. Two groups of specimens were coated with two different compounds of synthetic ashes, in which the first group was containing corrosive salts and the second was a calculated specific combination of mineral part of additive ash and corrosive salts. Specimens were exposed to high temperatures up to 120 h at 600 °C. Power plant observations, XRF, weight loss criteria, SEM and FESEM were used to study the hot corrosion, and results were compared with similar studies. It was concluded that magnesium sulfonate could not attribute to reduce the emission of sulphurous gases. Although the first group of the specimens was highly suffered from corrosion, the other group of samples was protected against hot corrosion and the weight loss was decreased considerably. Morphology and XRD picks of corrosion products were described, and it was also concluded that Na₄V₂O₇ and NaV₃O₈ compounds which are molten at 600 °C were responsible for hot corrosion. The additive inhibited corrosion through formation of Na₃VO₄ with 850 °C melting point and prevented the formation of sticky and corrosive compounds.     

Corrosion behavior of low-alloy steel containing 1% chromium in CO2 environments

Corrosion behavior of low-alloy steel containing 1% Cr (1Cr) with normalized (ferritic–pearlitic) and quenched-and-tempered (tempered martensitic) microstructures was investigated in CO₂ environments at 60 °C. The severe localized corrosion which was observed in N80 carbon steel, did not exist for 1Cr steel due to the formation of a compact and self-repairable Cr-rich scale. For 1Cr steel, the corrosion resistance with ferritic–pearlitic microstructure was better than that with tempered martensitic microstructure. An apparent corrosion scale spallation was observed on the surface of quenched-and-tempered 1Cr steel, while only slight scale spallation was seen for normalized 1Cr steel.     

腐蚀产物MgO对Fe基合金在固态和熔融NaCl-MgCl2 中高温耐蚀性能的影响

熔融氯化盐是下一代聚光式太阳能热发电站（第3代CSP）候选传热和储热介质,含MgCl₂的熔融氯化盐对金属传热管道和储热容器腐蚀后在其表面形成MgO,MgO对管道耐腐蚀性能影响尚不清楚。通过对比碳钢和3种Fe-Cr-Ni合金在固态（345 ℃）和熔融NaCl-MgCl₂（445和545 ℃）中的腐蚀行为,分析了MgO对4种试样在不同温度下的腐蚀行为机理。结果表明,在固态NaCl-MgCl₂中,碳钢表面MgO壳致密且连续,可以保护试样免受腐蚀。在熔融NaCl-MgCl₂中,4种试样表面也生成了致密的MgO壳,但它因热应力作用而开裂和剥落,熔融盐沿着氧化膜裂纹渗入MgO/基体界面,发生化学-电化学联合腐蚀反应,不能保护试样免受该熔盐腐蚀。     

Degradation processes in Al/SiCp/MgAl2O4 composites prepared from recycled aluminum with fly ash and rice hull ash

The degradation characteristics of Al/SiC_p/spinel composites prepared with fly ash (FA) and rice hull ash (RHA) under environmental conditions were investigated. Composite specimens were prepared with recycled aluminum via reactive infiltration in the temperature range 1050–1150 °C for 50–70 min and, in argon atmosphere at a pressure slightly above that of the atmospheric pressure. Results reveal that although both FA and RHA help in preventing SiC_p dissolution and the subsequent chemical degradation of the composites, due to the interaction of native carbon in FA with liquid aluminum, FA‐composites are susceptible to corrosion via Al₄C₃. Moreover, this phase accelerates the degradation process and increases the damage severity. The primary corrosion mechanism in both types of composites is attributed to microgalvanic coupling between the intermetallic Mg₂Si and the matrix. Accordingly, an appropriate control of the Si/(Si + Mg) molar ratio in the aluminum alloy hinders the Mg₂Si corrosion mechanism in both types of composites and a proper FA calcination prevents chemical degradation in FA composites.     

Corrosion behaviour of X52 pipeline steel in high H2S concentration solutions at temperatures ranging from 25°C to 140°C

Abstract

High temperature and high pressure immersion tests in an autoclave were employed to study the corrosion behaviour of X52 pipeline steel in aqueous solutions containing high concentrations of H₂S. The corrosion products generated were characterised using scanning electron microscope, energy dispersive spectroscopy and X-ray diffraction. It was seen that at a constant H₂S concentration of 22 g/l, the corrosion rate increased with increasing temperature up to 90°C, thereafter decreased at 120°C and slightly increased again at 140°C while the corrosion rate increased with H₂S concentration at a temperature of 90°C. When the temperature and H₂S concentration increased, the corrosion product converted from iron rich to sulphur rich products in the following sequence: mackinawite→troilite→pyrrhotite, where the microstructure and stability of the corrosion products had an important effect on the corrosion rate. The corrosion film was formed through the combination of the outward diffusion of Fe²⁺ ions and the inward diffusion of H₂S and HS^? species.