ABSTRACTIn refineries and oil and gas plants, air-cooled heat exchangers, so-called fin fan coolers, are fabricated from 22% Cr duplex stainless steels where type 300 series stainless steels would have problems with chloride pitting and chloride stress corrosion cracking (CSCC). Depending on application, limits are often specified for ferrite content and hardness (typically 35-65% for ferrite content and 320 HV maximum) during welding procedure qualification. Recent several cases of failures in hydroprocessing reactor effluent air cooler (REAC) system in refineries are now attracting worldwide attention to ferrite content and hardness in 22% Cr duplex stainless steel welds. In this study, welding trials were performed on 22% Cr duplex stainless steel UNS S32205 corner joints with different wall thickness similar to the top plate and tubesheet plate joint configuration used in a fin fan cooler header box. The effects of material thickness (15 mm, 25 mm, and 35 mm), weld heat input, and joint restraint during welding fabrication on ferrite content and hardness of the welds were evaluated. The results seem to suggest a need for careful re-evaluation of the upper limits of ferrite content and hardness for thick-wall 22% duplex stainless steel joint which are currently used.INTRODUCTIONDuplex stainless steels have a two-phase microstructure, approximately 50% ferrite and 50% austenite, and are often used in petroleum refineries and oil & gas plants where type 300 series stainless steels would have problems with chloride pitting and chloride stress corrosion cracking (CSCC). In recent years, plant users tend to prefer duplex stainless steels to type 300 series stainless steels considering the presence of chlorides in the external atmospheric environments. This trend has led to an increasing uptake of the use of these steels.The most commonly used grade of duplex stainless steel for air-cooled heat exchangers in petroleum refineries and oil & gas plants is 22% Cr duplex stainless steel (Alloy 2205; UNS S31803/S32205). When this steel is applied to welded components, limits are often specified for ferrite content and hardness (typically 35-65% for ferrite content and 320 HV maximum)1 during welding procedure qualification due to concerns that these may increase susceptibility to corrosion and cracking in service.
ABSTRACTErosion-corrosion, is a major problem in pulp/paper mill equipment. Erosion-corrosion in steels under caustic conditions is a challenging subject due to the particulate fluid with organics and non-Newtonian behavior. Fluid properties, liquor composition and process parameters affect corrosion rates in this regime. Studies have suggested that the flow may interfere with passive film formation in caustic conditions and significantly increase the corrosion rate.In order to better understand the mechanism of this corrosion process, electrochemical tests were performed on UNS G10180, UNS S31603 and UNS S32205, used in the construction of pulp/paper machinery components exposed to caustic environments. Rotating cylinder electrode (RCE) tests with linear polarization resistance (LPR) method were used to get instantaneous corrosion in a simulated white liquor (WL) solution with hard particles simulating conditions for the digesters or evaporators. Repassivation behavior of alloys under flow conditions was studied by using scratch tests. The results showed that G10180 was resilient at room temperature but corroded actively at elevated temperature, while S31603 showed sensitivity to flow especially at elevated temperature. S32205 provided good performance in the tested temperatures and environments without significant flow effects. Finally, a practical, qualitative measurement of “potential shift” after a scratch was introduced.INTRODUCTIONErosion-corrosion, defined as the loss of material under continuous, combined effects of mechanical and chemical environmental factors, is an important issue in the complex flow systems found in a number of chemical process industries.1-11 The recovery cycle, the pulper/repulper and even storage units are very important and essential pieces of the workings of a paper mill and can easily fall victim to the combined mechanical and chemical action of erosion-corrosion if improperly designed, used or monitored. However, the knowledge about erosion-corrosion in these systems is insufficient to provide scientifically justifiable methods to avoid equipment damage. This study is part of a broader effort to understand the erosion-corrosion mechanism and increase the reliability of materials used in the pulp and paper industry and beyond.
ABSTRACTEvaluation of corrosion inhibitors for high temperature (HT) upstream oilfield applications can be challenging due to fixed fluid volume testing typically encountered in laboratory testing. A series of laboratory testing methodologies were conducted to further elucidate the factors which affect laboratory corrosion inhibitor performance in high temperature conditions. Under certain HT conditions, inhibitor performance may be skewed due to testing effects which may occur in closed cell testing such as Fe2+ saturation and/or scaling of the test fluids which may artificially lower the overall general corrosion rate. This testing program was designed to minimize these effects and ensure that corrosion inhibition in laboratory testing is identified solely due to performance of the inhibitor. For these studies, corrosion measurements in stirred autoclaves were performed by linear polarization resistance (LPR) or with weight loss measurements in rotating cage autoclaves (RCA). Surface morphology of corrosion products, scale deposition and effects of localized attack were evaluated by microscopic evaluations. Factors affecting inhibited and uninhibited general corrosion rates measured in laboratory test environments such as brine composition, effect of scale inhibitor inclusion, effect of metal surface area to fluid volume ratio, and method of acid gas charging were evaluated.INTRODUCTIONAmine based film forming corrosion inhibitors (CI) have been used extensively to control internal corrosion experienced as a result of production of oil, gas, and produced water in upstream environments. Although extensive research in various test methods have shown the ability to qualify corrosion inhibitors at temperatures < 100°C, a better understanding of the parameters which affect corrosion processes at temperatures > 100°C is necessary.CO2-dominated fixed volume fluid testing has long been a challenge of laboratory corrosion inhibitor evaluations as brine chemistry, pH, concentration of Fe2+, etc. can change throughout the duration of the test affecting both the overall general corrosion rate and subsequent performance characteristics of the inhibitor.1 This phenomenon is especially evident in high temperature (HT) testing as elevated temperatures encourage the formation of passivating FeCO3 and/or mineral scales which can result in an overall artificial reduction of the corrosion rate.2-5 Closed cell laboratory testing relies on a fixed fluid volume in which accumulation of corrosion by-products can alter bulk fluid chemistry as well as the resultant steady state corrosion rate.1 Laboratory simulations differ from field conditions as the bulk fluid properties in the field will be less prone to significant changes in fluid chemistry encountered in fixed volume tests. Therefore, proper CI selection in laboratory evaluations should mimic as closely as possible the corrosive condition expected in the field.
Kim, Chuljung (Samsung Heavy Industries) | Hwang, HyangAn (Samsung Heavy Industries) | Oh, TaeJin (Samsung Heavy Industries) | Lim, ChaeSeon (Samsung Heavy Industries) | Jansen, Edward (American Bureau of Shipping / Technology) | Eliasson, Johnny (Chevron / Material and Corrosion) | Chaloner-Gil, Benjamin (Chevron / Material and Corrosion) | Quintero, Martin (Chevron / Material and Corrosion) | Shin, PyoungHwa (Pukyong National University) | Shon, MinYoung (Pukyong National University)
ABSTRACTOffshore platforms are operated for more than 30 years without re-docking in severely corrosive environment. Therefore, higher level of quality is required not only to reduce maintenance cost but also to keep long term service life time.In maintenance point of view, coating and surface preparation are matter of the most importance. Especially, water soluble salts contamination on steel surface can significantly affect adhesion strength at the interface of steel and coating.To study the effect of water soluble salts affecting long-term durability of carbon steels coated with epoxy paint, the carbon steel surface was contaminated by different soluble salt concentration. Based on NORSOK M-501 and ISO 20340 test method, sea water immersion and cathodic disbonding test were carried out for 6 months. Visual observation and pull off adhesion test were conducted. In addition, the phenomenon that the solute is accumulated on the contaminated boundary layer (Coffee Ring Effect) was studied.Consequently, the results show that 50 mg/m2 and less of salt contamination levels was closed to reaching an acceptable coating performance. Additionally, it was confirmed that the thicker coating showed the better adhesion property.INTRODUCTIONContamination in the form of sea salts is common in a marine atmosphere. If surfaces contaminated with sea salts are coated and later immersed, moisture will penetrate the coating film to the contaminants. At first, the contaminant attracts moisture, resulting in a saline solution. In order to thin solution more moisture penetrates the coating until equilibrium has been reached. Therefore, blistering will occur in these areas. This phenomenon, called osmotic blister, leads to the deterioration of paint system in a very short period of time.Off-shore platforms are operated more than 30 years without re-docking. Therefore, it is necessary to keep high quality coating performance for long-term operation period without maintenance.As a result of pre-analysis of paint specification for four oil major companies, it was confirmed that each company has different acceptance grade of salt contamination level and there was no correlation between design life time and soluble salt concentration shown in Table 1.
ABSTRACTResistance testing of low alloyed steel pipes to Hydrogen Induced Cracking (HIC) is performed according to NACE standard TM0284. Within the latest revision of this standard in 2016, fitness-for- purpose testing, where the test environment and partial pressures of gases appropriate to the intended application are selected, has been included. Mildly sour service conditions may require testing under less severe conditions. Compared to the standard test duration of 4 days, longer test durations up to 90 days can be required in the newly added test solution C.HIC tests have been performed for several SAWL large diameter pipes of grade X65-X80 designated for sweet or mildly sour environments at hydrogen sulfide partial pressures between 100 kPa and 0.5 kPa at different pH values between 3.3 and 5.8 in NACE TM0284 standard test solutions. For evaluation, the new ultrasonic procedure of NACE TM0284-2016 has been used as well as standard metallographic evaluation by equidistant sectioning of some specimens and determination of the CLR, CTR and CSR. Test results are compared after 4 days and the designated longer test durations. Based on the different test durations, material dependent HIC resistivity trends can be observed for the different pipe materials.INTRODUCTIONSteel pipelines designated for the transport of oil and gas containing wet hydrogen sulfide (H2S) are faced with the risk of sudden and severe cracking. In sour environments containing water and H2S, hydrogen atoms, originating from the anodic dissolution of the material, can diffuse into the steel and induce severe damage. Different forms of cracking may occur, such as Hydrogen Induced Cracking (HIC), Sulfide Stress Cracking (SSC) or Stress Oriented Hydrogen Induced Cracking (SOHIC).1.2 These cracks can often be difficult to detect in routine inspections and are thus regarded as a higher risk for integrity loss than weight-loss corrosion. Due to the sudden and unforeseeable appearance of these failure mechanisms it is in general necessary to use HIC resistant pipeline steel for all sour applications.
Clark, Brandi N. (National Institute of Standards and Technology) | Rentz, Ross (National Institute of Standards and Technology) | McColskey, J. David (National Institute of Standards and Technology) | Sowards, Jeffrey W. (National Institute of Standards and Technology)
ABSTRACTCarbon dioxide (CO2) capture and sequestration has been hailed by some as the “critical enabling technology” needed to reconcile climate-change-driven reductions in CO2 emissions with the use of fossil fuels to meet increasing energy demands. However, transporting large quantities of CO2 would require a pipeline network the size of the existing natural gas network and a similar level of regulation. Unlike CO2 currently transported for enhanced oil recovery (EOR), anthropogenic CO2 is expected to contain corrosive contaminants associated with energy production (e.g., H2O, SOx, NOx, H2S). In order to successfully transport large volumes of anthropogenic CO2, the level of contaminant removal needed for pipeline safety and integrity will need to be balanced against the cost of CO2 purification. Gaps in the existing literature demonstrate a need for systematic investigation (through improved metrology) of the effect of expected contaminants on corrosion rate to inform pipeline design decisions. To address this issue, NIST has constructed a supercritical CO2 corrosion test facility. The facility is equipped with 3 high-temperature, high-pressure vessels and a gas-phase Fourier transform infrared spectrometer (FTIR) for simultaneous in situ monitoring of key contaminants. This paper outlines the capabilities of the new NIST facility, describes our corrosion test method, and reports preliminary corrosion test results.INTRODUCTIONAs the estimated costs of a changing global climate climb ever higher,1 there is increasing pressure to dramatically reduce carbon dioxide (CO2) emissions worldwide. In the United States, an estimated 40 % of these emissions are a result of electrical power generation.2 To reconcile the need for a reduction in CO2 emissions with increasing energy demands, carbon capture and sequestration (CCS) has been hailed by some as the “critical enabling technology” to allow the continued use of coal and other fossil fuels.3 In the context of reducing anthropogenic CO2 emissions, CCS can be viewed as a three-step process, involving: (1) capture of CO2 at the power plant; (2) transport of CO2 to a suitable location; (3) injection into underground rock formations for storage.2 While there has been considerable research concerning capture technologies and suitable injection sites, the safe, effective transport of CO2 through pipelines has received relatively little attention.4 Currently, approximately 68 million metric tons per year of CO2 are transported by pipeline over relatively short distances;5 capture of 80 % of current emissions would require transporting approximately 1630 million metric tons (1800 Mt) of CO2 (24 times more).4 It has been predicted that the pipeline network necessary to transport this new CO2 would rival the size of the current natural gas pipeline infrastructure, and it is expected that federal regulation of these pipelines will increase accordingly.4
Yan, Li (CanmetMATERIALS Natural Resources Canada) | Xu, Luyao (Stantec) | Gravel, Jean-Philippe (CanmetMATERIALS Natural Resources Canada) | Kang, Jidong (CanmetMATERIALS Natural Resources Canada) | Arafin, Muhammad (CanmetMATERIALS Natural Resources Canada)
ABSTRACTIn this work, stress corrosion cracking (SCC) of X80 and X100 pipe steels under various cathodic protection (CP) levels in near-neutral pH environment was investigated. The results showed that X100 tended to form longer SCC cracks compared to X80 steel. The crack depth exhibited normal/quasi- normal distributions for both materials. Only a small fraction of cracks within the total number of cracks formed would propagate deep into the steel. It was revealed that the effect of CP on the occurrence of SCC in X80 and X100 steels was different. For X80 steel, CP exhibited an inhibiting effect on both SCC crack initiation and propagation by controlling the anodic dissolution process of steel and the inhibiting effect increased with CP level. The mitigating effect of CP on crack initiation was more significant than that on crack propagation. For X100 steel, it was observed that hydrogen evolution and absorption played an important role in crack initiation, while anodic dissolution of steel dominated the crack propagation process. The increase of CP level could cause more cracks to initiate but retard the crack propagation.INTRODUCTIONWith the rapidly increasing energy demand, the oil/gas production and pipeline activities can be found in remote regions such as the Arctic and sub-Arctic ones in North America. These areas are featured with geological hazards including permafrost and semi-permafrost, landslide, etc. High grade steel pipelines such as X80 and X100 steels have been used in recent years in these harsh regions for economic benefit and service reliability reasons.1-6 During service, the reliability of these buried pipeline depends on a various factors including operational conditions, third-party damage, ground movement, corrosion and stress corrosion cracking (SCC), etc. In particular, SCC has been identified as one of the major threats resulting in pipeline failures.7-9Cathodic protection (CP) in conjunction with coating is generally recognized as the most effective mitigation method for pipeline protection against corrosion. Some research has been carried out to study the effect of CP on SCC cracking.10-12 Parkins10 studied the mechanical property of X65 steel and its SCC susceptibility at various CP potentials and observed that potentials more negative than open circuit potential (OCP) could decrease the ductility of steel and hence increase the susceptibility of steel to SCC. Liu12 investigated the occurrence of SCC on various pipeline steels as a function of applied CP potential and found out that the mechanism of CP effect on SCC cracking changed within different CP potential ranges, i.e., CP effect was primarily showed on anodic dissolution when the CP potential was more positive than -730 mVSCE, and the CP effect was dominated by hydrogen evolution and absorption when potential was more negative than -920 mVSCE. All these findings were based on short-term tests, usually a couple of weeks. In the real situation, the occurrence of SCC cracks in the field could take much longer. This study was intended to carry out a systematic investigation of CP effect on SCC crack initiation and propagation through relatively long-term tests. A static load method with a proof ring setup was employed to study the CP effect on SCC crack initiation and propagation.
ABSTRACTFor over three decades, the water treatment industry has extensively relied on phosphorous-based chemistries to control corrosion of low-carbon steel alloys. While these chemistries have frequently proven effective, they have always come with the underlying concern of precipitation with soluble calcium in the bulk-water, causing fouling and loss of inhibitor within the system. To combat these fouling concerns, water treatment professionals typically need to add sulfonated polymers to stabilize the inhibitor in solution, driving the overall cost for an effective corrosion inhibitor program higher. Unfortunately, precipitation and fouling can still occur, either due to product overfeeding or upsets in water chemistry. As water regulations become more stringent and systems operate at higher cycles of concentration, the challenge of preventing loss of phosphorous based chemistries to precipitation with calcium is likely to become even more difficult and costly. When you factor the increasing regulations on phosphorous-based chemistries that are making it more difficult and costly to discharge process water, it is clear an alternative to phosphorous-based chemistries is desperately needed in the industry.This paper presents a new phosphorous free corrosion inhibitor that eliminates many of the problems and looming regulations associated with phosphorous based inhibitors. This new inhibitor simplifies corrosion control in cooling systems by eradicating the concern of precipitation with calcium. Simultaneously, it provides comparable or even better corrosion protection to phosphorous based inhibitors. This inhibitor has the ability to maintain excellent corrosion protection in high calcium containing stressed waters, where phosphorous based inhibitors struggle to perform. It performs well in both low and high hardness waters and across a wider pH spectrum than phosphorous-based inhibitors. Furthermore, this new inhibitor is made from sustainable sugar feedstocks and is an environmentally friendly alternative to phosphorous based inhibitors. This paper will present corrosion inhibitor performance data using electrochemical test methods, additional laboratory testing and pilot test results to demonstrate this new inhibitor's performance benefits, overall effectiveness and value to the water treatment market.
Al-Ali, Samir K. (Kuwait National Petroleum Company) | Alshammari, Husain J. (Kuwait National Petroleum Company) | Al-Refai, Faisal H. (Kuwait National Petroleum Company) | Bhatia, Vinod K. (Kuwait National Petroleum Company) | Al-Otaibi, Mohd. (Kuwait National Petroleum Company)
ABSTRACTWith new advancements in the petroleum refining processes, the need for monitoring of corrosion on the new and old systems is also transforming. This paper describes the experience gained in monitoring of stagnant and low flow lines of a refinery in Kuwait After witnessing a failure in one of the de-salter relief lines of the crude distillation unit, a comprehensive plan was prepared to identify and address similar cases in the entire refinery which was a major challenge.This paper describes the probable causes and the adopted remedies for the localized corrosion observed in the insulated de-salter relief line. Circumstantial evidence and failure morphology were studied in arriving at the root cause for this failure. Although, samples of the pipe showed signs of aggravated external corrosion at the failure location after removal of insulation, the reason assigned for the failure was due to under-deposit corrosion mainly on the pipe internal side.Based on the findings and experience gained from the above case, an advanced Non Destructive Testing (NDT) e.g. Long-Range Ultrasonic Testing (LRUT), profile radiography etc. methodology for the monitoring of other stagnant and low-flow was prepared and is currently under implementation.INTRODUCTIONThe operation of refineries is a continuous process which means that any process in any unit/plant of the refinery usually an uninterrupted operation; unless it is stopped by any planned or emergency shutdown. However, various sections of equipment and piping remain practically stagnant or experience low flow (≤ 0.5 m/s). In majority of the cases, these locations go un-noticed due to low operational or process importance. However, these cases are extremely important when studying corrosion related to the equipment and piping systems. This paper discusses case studies of localized / under deposit corrosion in low flow or stagnant flow lines in a petroleum refinery. The paper also discusses the mechanism related to stagnant and low flow conditions. The aim of this paper is to present a philosophy for identification of such cases and to present a monitoring strategy for preventing unwarranted on-stream failure.
Wang, Bei (University of Science and Technology Beijing) | Zhang, Lei (University of Science and Technology Beijing) | Chen, Guang (University of Science and Technology Beijing) | Li, Qingping (CNOOC Research Institute) | Chang, Wei (CNOOC Research Institute) | Yao, Haiyuan (CNOOC Research Institute) | Liu, Yingkun (Safetech Research Institute) | Zhang, Yunan (Safetech Research Institute)
ABSTRACTCorrosion is always recognized as one of the biggest flow assurance challenges of natural gas fields. During the pipeline design and maintenance, it is not enough to only use the equations of the limitation for the maximum erosional velocity from API RP 14E to deal with the balance of pipeline diameter, flow rate and the corrosion inhibitor film stability and effectiveness. In order to get more information of the relationship between flow and inhibitor for wet subsea pipeline, a HTHP-RC and a wet gas flow loop were employed to simulate typical flow conditions of subsea gas pipeline in this paper, as well as the research of corrosion behaviors before and after inhibitor injection. The stability of inhibitor film on the pipeline steel's surface under high gas velocities under the CO2 wet gas corrosion environment was evaluated. The influence of pipeline operating parameters such as gas velocity, wall shear stress, CO2 pressure, total pressure, and inhibitor dosage, was investigated during the HTHP-RC tests and flow loop tests. The results give the recommendation of the gas velocity and the inhibitor limits of the subsea wet gas pipeline.INTRODUCTIONWith the development of deep water offshore gas fields in recent years, long distance subsea gas pipelines have been built up and flow assurance becomes more and more important. The need to maintain gas production at reducing reservoir pressure had already resulted in much higher gas velocities in the field.However, higher gas velocity leads to higher wall shear stress. Generated wall shear stress in some high flow velocity systems can reach 300 Pa. Gopal et.al indicated that shear stress can reach 80-160 Pa in slug flow. In addition, values as high as 3000 Pa have been recorded in some laboratories.1-3A high wall shear stress can be detrimental to the corrosion inhibitor adsorption on the internal surface of a pipeline, which will increase the corrosion and erosion risk especially for wet gas transportation. For some inhibitors, the inhibitor film on the steel surface can be destroyed by the fluid when the wall shear stress is higher than a critical value.4 Some authors claim that above a certain critical fluid velocity, corrosion inhibition would no longer be possible,5 but some indicate that the inhibitor can still protect steel by increasing the concentration even at a high flow velocity.6 But anyway, it is necessary to determine the critical erosion velocity and the concentration that corrosion inhibitor can filmed on the surface stable under the condition with high flow velocity during the pipeline design and maintenance.