Structure surfaces damaged by corrosion may develop stress concentrations which lead to initiation of cracks and possible crack growth.
Simulation of the galvanic effects leading to corrosion takes account of the properties of the electrolyte as well as the structural materials, to determine electric fields within the electrolyte, attenuation in the return path, and the surface current densities and potentials. If dissimilar materials are present or a CP system is not adequately designed, areas may exist where anodic current occurs on a structural surface, causing mass loss from the surface. The magnitude of the anodic current density, determined from simulation, can be used to determine surface shape change.
Such shape change generally results in indentations, which act as stress-raisers. Simulation to determine magnitude of the stress concentration can identify likely sites for crack initiation. The possibility of crack growth, and the time taken for the growth, can be determined using fracture and crack growth simulation.
This paper explores the combined use of galvanic simulation and fracture/crack growth simulation.
Firstly galvanic simulation is used to investigate the influences of parameters, including electrolyte thickness and conductivity, on rate of corrosion for a galvanic cell caused by a metallic sample in contact with a more noble material. The paper reaches conclusions regarding the type of environment that is likely to produce higher penetration rates and where this might occur.
Secondly, having removed material from the surface (corresponding to corrosion occurring over a given time), fracture simulation is used to evaluate the stress concentration, initiate cracks, determine stress intensity factors, and identify vulnerability to fatigue failure. This crack growth takes into account the corrosion damage and inherently includes local stress concentration due to the damaged surface. In the crack growth simulation, the full crack path and direction are determined along with the fatigue life.
This paper provides a methodology that can be used by design engineers, to identify possible problems on a structure, giving scope to change designs and so reduce possible failures and in-service repair costs. This methodology identifies areas of the structure that have the greatest risk of damage - which may not be obvious without combined corrosion and fracture simulation; and so provides more informed targeting of locations where “what if” fracture mechanics assessments should be applied.
The heat-treatable and weldable alpha-beta titanium alloy, UNS R55400,(1) was developed as a higher strength alternative to the highly corrosion-resistant UNS R56404 (ASTM Grade 29) (2) titanium alloy used as tubular components for corrosive, extreme high pressure, high temperature (XHPHT) and deep water hydrocarbon production service. Recently approved for sour service, (1) this alloy exhibits very comparable resistance to UNS R56404 in acidic, sour and non-sour chloride-rich aqueous environments commonly associated with upstream and offshore hydrocarbon production. This paper presents an expanded laboratory test database on critical corrosion modes for UNS R55400 pipe exposed to relevant oilfield production environments which include sour well fluid brines, a heavy chloride/bromide brine well completion fluid, injected methanol, organic acid- and HCl-based well acidizing solutions, and seawater. The alloy’s elevated reducing acid chloride resistance exhibited in these tests is correlated with electrochemical parameters derived from cathodic/anodic polarization testing and alloy corrosion rates derived from dilute boiling HCl media. Corrosion performance comparison between UNS R55400 and other common high strength oilfield titanium alloys is made across these specific production service environments to provide guidance for alloy selection and use.
The new UNS R55400 titanium alloy2 was developed as a higher strength alternative to ASTM Grade 29 titanium (UNS R56404) 3-5 for highly stressed tubular and forged components used in corrosive, high pressure, high temperature (HPHT) energy extraction service. Relevant, projected applications include offshore production risers, deepwater well-work over/completion/landing, tubular strings, drill pipe strings, and deep sour HPHT well Oil Country Tubular Goods (OCTG)/production tubing and liners.
This heat-treatable alpha-beta titanium alloy features higher strength (862 or 896 MPa minimum yield strength), elevated strength-to-density for lighter weight components, and an overall corrosion resistance similar to that of UNS R56404. With the nominal composition in weight percent of Ti-5.5Al-4.3Zr-5.7V-1.3Mo-0.10 O-0.06Pd, this extra low interstitial (ELI) alloy formulation ennobled via minor Pd addition6 was designed to resist crevice and stress corrosion, and provide good fracture resistance in aqueous chloride environments up to ~300°C, while being highly weldable via fusion or solid-state welding methods.
Bergman, Jeffrey (Acellent Technologies Inc.) | Chung, Howard (Acellent Technologies Inc.) | Janapati, Vishnuvardhan (Acellent Technologies Inc.) | Li, Irene (Acellent Technologies Inc.) | Kumar, Amrita (Acellent Technologies Inc.) | Kumar-Yadav, Susheel (Acellent Technologies Inc.) | Chapman, Daniel (Chevron Energy Technology Company) | Nissan, Andrew (Chevron Energy Technology Company) | Sarrafi-Nour!, Reza (Chevron Energy Technology Company)
In order to ensure the continued operation of fixed equipment assets such as vessels, pipeline and piping systems, operators must invest in regular inspection of their systems by a variety of methods, including visual inspection, inline inspection (ILI), and traditional non-destructive evaluation (NDE) based techniques. This results in intermittent inspection of the piping and increased operating costs. Alternately, by utilizing Structural Health Monitoring (SHM) systems operators can monitor pipelines and piping on a continuous, rather than intermittent, basis and drive toward more cost effective Condition-Based Maintenance (CBM) of their systems. To support this need, a system is being introduced, which allows for the detection, localization and quantification of corrosion and erosion damage in metal piping. This system enables monitoring over an extended region of the pipe surface providing information on defect size and location in addition to the remaining wall thickness.
The system consists of a network of miniature ultrasonic sensors embedded in a thin dielectric film that can be integrated with the pipe. Diagnostic hardware housing data analysis software is used to acquire data from the sensor network and to determine onset and progress of corrosion damage. This paper discusses validation testing work performed using the system on piping.
Energy refining and distribution by the oil and gas industry is a key component of modern infrastructure. Corrosion and erosion are significant concerns for operators especially as economics drives the expectations for long life of their fixed equipment assets. These assets such as piping, pipelines, pressure vessels and tanks are vulnerable to both internal and external corrosion, which can result in deterioration of the pressure boundary. As a result, there is a need for regular inspection of steel pipeline for corrosion/erosion damage to monitor for wall loss on both the external and internal surfaces [1-2].
The design of offshore wind foundations is still evolving as large projects are being commissioned or planned for the northern part of Europe. Monopile foundations represent the most common design, but other structure types are also being installed, such as jackets, tripods and gravity foundations. In comparison with offshore structures for oil and gas production, wind foundations present some new challenges for corrosion protection. As the structures are unmanned, the requirements for operation and maintenance must be kept at a minimum. At the same time, the huge water volume in the closed compartment of monopiles raises some concerns about MIC at seabed. The cathodic protection (CP) being applied both outside and inside also involves certain challenges. In this respect, several new approaches for inspection and corrosion monitoring have been applied. The paper reviews specific corrosion risks, such as macro galvanic elements, MIC and insufficient CP. Experiences from evaluating such issues by using various inspection and monitoring techniques are discussed. The applied techniques include UT examination, CP surveys with drop cells and environmental depth profiling. Corrosion has been evaluated using both small coupons and full-length coupons, while real-time measurements have included ER sensors as well as potential and current measurement.
The design of offshore wind farm foundations is still evolving in order to reduce Cost of Energy and harness energy in locations at greater depths. At the same time, there is a demand for larger turbines with an increased reliability to minimize costly offshore maintenance. This tendency creates an increasing need for customized inspecting and monitoring of the structural integrity of wind turbine foundations. While the methods applied to offshore oil and gas installations are well-established, the strategies for offshore wind structures still undergo a learning curve. Experiences from early projects are steadily growing, but simultaneously the designs in new projects change to optimize performance and costs.
Large offshore wind farms have existed for 10-15 years. Today, 80 major offshore wind farms and 2850 turbines are operating in the northern part of Europe. Most of the foundations are based on the monopile design, but other structure types are also being installed, such as jackets, tripods and gravity foundations.
Siegmund, Gerit (ExxonMobil Production Deutschland GmbH) | Schmitt, Guenter (IFINKOR-Institute for Maintenance and Corrosion Protection Technologies n.f.p.Ltd.) | Kuhl, Lars (IFINKOR-Institute for Maintenance and Corrosion Protection Technologies n.f.p.Ltd.)
The SSC and SCC performance of duplex steel UNS S31803(1) (1.4462) and superduplex steel UNS S32760 (1.4501) was tested with welded round tensile bars under constant load of 90% AYS (measured at the test temperature) fully submerged in brines with 10 to 45 g/L chloride in the presence of 150 mg/L bicarbonate under partial pressures (at test temperature) of 5 bar CO2 plus 0.5, 0.7 and 1.0 bar H2S at temperatures of 28.5, 90, 100, 130 and 180°C with an exposure time of 720 h. In none of the corrosion systems tested cracking was observed. Moderate localized surface activation was encountered yielding mostly shallow pits due to selective phase dissolution. It appears that the performance profile of these groups of stainless steels is still not completely known specifically at higher temperatures, and is obviously largely underestimated.
Continuous and cyclic steam injection is a long known technique to enhance oil production from reservoirs containing heavy crudes. 1,2 ExxonMobil Production Deutschland GmbHߙ plans to enhance existing steam injection in an older oil field raising the current well head temperatures from about 100 °C to approximately 180 °C. Although there are various similar applications around the world, materials selection for this application is challenging because environmental conditions differ considerably from field to field and cannot easily be compared. Important variables are:
• water-oil ratio (WOR)
• chloride and bicarbonate content of brine
• partial pressures of H2S, CO2
• pH under production conditions
• presence of oxygen
High Temperature Hydrogen Attack (HTHA) is a complex damage mechanism that continues to defy investigators trying to make predictions on the anticipated degree of damage or service life. This article provides some background on HTHA, discusses some current developments in HTHA inspection and mitigation, and describes how several refiners have instituted an HTHA risk management plan for their refineries and the challenges and pitfalls they have encountered. This paper also describes a new innovative screening methodology that has been used to screen over 100 equipment items operating in high temperature hydrogen services that needed individualized risk management plans. Materials included in the evaluations are carbon steel (CS), C-0.5Mo, C-Mn-0.5Mo, 0.5Cr-0.5Mo, 1Cr, and 1.25Cr equipment ranging in service exposure of 10 to over 50+ years. Several examples are provided.
The Pono Division of Becht Engineering*, has developed a practical and simple-to-use approach to prioritizing the inspection and replacement of equipment in High Temperature Hydrogen Attack service. This approach utilizes the existing and accepted API 941 “Nelson Curve”, but adapts it to better fit the realized operating conditions at an individual facility, based on several factors that have not been previously considered.
Historically, the industry has used experienced-based curves (API 941 Nelson Curves) in the selection of materials as well as for evaluating existing in-service equipment.1 These curves have served the industry well, but in the past 5 years, there have been several notable cases of HTHA that fall below the established curves and there is still a sizeable base of C-0.5 Mo equipment operating above the carbon steel curve. Therefore, industry needed a more realistic method for evaluating existing equipment in HTHA services.
It is important to note that previously, the only two determinants used in modeling HTHA susceptibility have been partial pressure of hydrogen and operating temperature. However, there are several other operating conditions that can significantly increase or decrease susceptibility to HTHA. This method attempts to modify both the accepted “Nelson Curve” for each material, as well as modify the operating conditions to consider many more factors that affect HTHA. This method still starts with the hydrogen partial pressure and temperature, but then takes into account other driving forces such as cladding type, corrosion scale and fouling, thickness, and confidence in operating data.
Installed ultrasonic sensor systems are becoming more commonly used and accepted as a method to improve data integrity and increase productivity for Oil & Gas asset inspections – especially with underground, insulated, offshore, and other hard-to-access thickness monitoring locations (TMLs). Example applications where installed sensor technologies have been deployed successfully include crude overhead lines, sour water service, offshore risers for sand monitoring, and midstream buried pipelines. Many additional applications of these systems are anticipated to augment static thickness monitoring, improve the accuracy of thickness data/trending, and reduce pressure-boundary penetration of conventional corrosion probes while allowing both remote and real-time monitoring where desirable. This paper will review the development of a new, flexible, permanently installed monitoring system. Concepts for optimizing the measurement system will be discussed, including hard-wired and wireless approaches, proper transducer selection, temperature compensation, and statistical data analysis.
Metal loss due to corrosion and erosion is a widespread issue in the oil and gas (O&G) and Power Generation industries for tanks, high-energy piping, pressure vessels, and other critical assets. Metal loss can result in loss of pressure containment, with resulting consequences that can include loss of life, damage to assets, disruption of service, environmental harm, loss of public image, and fines. As such, asset inspections are required by operators and are mandated in regulations and codes such as 29CFR-1910; API1 570, ASME2 Sections V & XI, ASTM3 E797, and NACE4 IP 34101.
While there are many methods for measuring wall thickness, a predominant method is the use of portable ultrasonic equipment. Ultrasound is non-intrusive, accurate, and relatively low cost to employ in most situations. However, it does have several shortcomings, including that the ultrasonic transducer or probe needs to be applied in direct contact to the external surface of the pipe; this sometimes requires scaffolding, excavation, and stripping of coatings or insulation. Thus, the cost of access to the structure often far exceeds the basic cost of inspection. Furthermore, a trained and certified inspector is required to operate the ultrasonic instrumentation, requiring personnel to sometimes be exposed to potentially hazardous environments. The accuracy and repeatability of ultrasonic measurements are operator-dependent, and recent studies have shown that the probability-of-detection (POD) can be poor1. Finally, the measurements are only performed periodically, taking a snap-shot of plant condition.
Microbiologically influenced corrosion (MIC) is a significant challenge in the oilfield that results in substantial cost for the operator in downtime, pipe and equipment replacement, and safety hazards associated with failures. Although biocide treatments are usually performed to minimize the risk of MIC, this is often challenging to control a microbial population present as a biofilm. To this end, a novel biocide has been developed to provide enhanced microbial kill within a biofilm as well as biomass removal. The novel biocide was evaluated against biofilm populations grown in anaerobic conditions in bioreactors. The results indicated that the new chemistry provided superior results when compared to commonly used and best-in-class products. Enhanced microbial kill and removal of biomass was evidenced by Confocal laser Scanning Microscopy of biofilms grown on the surface of C1018 carbon steel coupons. Further, additional tests demonstrated that the novel product neither negatively impacts the oil and water interface nor causes corrosion in the metallurgy.
Microbiologically-influenced corrosion (MIC) poses a serious concern to production and integrity of pipelines, vessels and tanks and can have a significant impact on the cost of operations in oilfields. As the assets age, the increasing water cuts directly potentiates the risk for MIC, as the microbial load in the system become more prominent. MIC is estimated to account for up to 20% of the costs associated with pipeline integrity, exceeding $2 billion USD per year.1,2 Microbes can be introduced in oil/gas production systems from the initial steps of drilling and completion of a well and during shut ins. Microbes can also be introduced during secondary and tertiary oil recovery, when fluids are injected into the formation to maintain reservoir pressure and push hydrocarbons out. Moreover microorganisms can exist endogenously in the petroleum reservoir. 3 The diversity of microorganisms found in oil/gas production systems is extremely broad, with well over 800 documented genus identified to date. 4 These microbes, under certain environmental conditions, are capable of causing significant challenges in oil and gas systems such as microbiologically influenced corrosion (MIC), biotic hydrogen sulfide (H2S) production, and biofouling of membranes, filters, and heat transfer equipment. Microbial risks become significantly more challenging when the microbial community colonizes parts of the system, forming biofilms that can increase the rates of localized corrosion, ultimately leading to leaks and failures.
The occurrence of localized corrosion in Top of the Line Corrosion (TLC) was investigated in a sweet (CO2-dominated) environment, with a focus on understanding the influence of the environmental parameters on localized TLC in order to develop a narrative for the mechanism.
A unique setup was developed for the experimental work, involving the use of carbon steel inserts exposed to three different levels of cooling at the same time. This concept was quite successful in simulating realistic localized features. A series of long term exposure (one- to three-month) experiments was conducted to investigate the controlling parameters. The occurrence of localized corrosion could be very clearly correlated to the condensation rate, the gas temperature and the organic acid content. Additional statistical information related to the morphology of localized TLC features could be made, providing useful insight on the mechanisms involved.
When significant heat exchange is present between the wet gas pipelines and the surroundings (frozen land, deep-sea water, etc.), water and hydrocarbon vapor can condense on the inner pipe wall and lead to severe corrosion issues . This phenomenon called Top of the line corrosion (TLC) is inherently a localized process. Corrosion occurs in specific areas along the line and the attack is not usually extended to large sections. This localized aspect is often related to situations where high condensation rates occur, i.e. where the gradient of temperature between the produced fluid and the outside environment is large. In sweet environments (CO2-dominated), the corrosion process is often characterized as a mesa attack: the steel is not uniformly corroded but the pits are usually wide, often flat-bottomed and bare of any layers, surrounded by areas with intact corrosion product layers.
The localized nature of TLC is still not well understood. The corrosion features observed in the field can be so large that the corrosion process is often referred to as “localized uniform corrosion” instead of a just “localized corrosion”. The unique TLC scenario where droplets of condensed water appear and are renewed continuously at the metal surface must play a crucial role. It is likely that the condensation process initiates and promotes the localized corrosion at the top of the line by challenging the protectiveness of the iron carbonate layer.
The aim of this research focused on obtaining an understanding of the role of chromium in a binary iron aluminides in aqueous environments, i.e. 0.25 M sulfuric acid. Using a binary Fe-26Al and X8 CrNiS 18-9 alloy for comparison purposes, electrochemical potentiodynamic polarization was undergone. All three alloy demonstrated a change on oxide during passivation. The addition of chromium demonstrated the highest corrosion current density yet the lowest and widest passivation range.
Iron aluminides pose high potential for substitution of current materials implemented in hightemperature applications due to such preferred properties as high strength-to-weight ratios and superior oxidation resistance. Additionally, the lucrativeness and ease of fabrication provide a further initiative to instigate the transition from current cost intensive stainless steel and nickel-based alloys to this intermetallic phase. The full commercialization of these materials has been hindered due to a limited ductility at room temperature and a certain reduction in strength when exposed long-term to temperatures exceeding 550°C. Despite this drawback for high-temperature applications, the benefits that iron aluminides pose can also be applied to room-temperature situations. In order to ensure such an implementation, the influence of aluminum content and ternary elements on the resulting microstructure and mechanical properties has been partially investigated. Nonetheless, an extension of the existing research to include the behavior of iron aluminides in aqueous environments must be achieved.
Due to the success of alloying chromium to steel, the impact of chromium on iron aluminides has been investigated and an improvement in ductility and other mechanical properties, as well as oxidation resistance, has been shown [1-4]. Nonetheless, the role chromium plays in the corrosion behavior of iron aluminides in aqueous solutions has only been meagerly examined . Furthermore, those investigations simultaneously considered the influence of chloride ions to the electrolyte [1, 5, 6]. As chloride ions have been identified as corrosion instigating components that result in pitting corrosion, these results cannot be directly correlated with corrosion in non-chloride containing solutions.