Jotun signed an agreement with Wallenius Wilhelmsen to provide its Hull Performance Solutions (HPS) antifouling coating system across 42 vessels in the leading shipowner’s advanced RoRo fleet.
HPS combines premium SeaQuantum X200 antifouling with technical and digital solutions to accurately measure hull performance. The antifouling works to increase vessel efficiency, cut fuel costs and reduce CO2 emissions.
“This is a major contract with a true global leader within this industry niche,” said Ulf Skovli, regional sales director, Jotun Marine Scandinavia. “Wallenius Wilhelmsen is a respected shipowner and operator that is known for its commitment to innovation, optimal operational standards and environmental care. It’s therefore hugely gratifying that it has chosen Jotun as ‘solutions partner’ for the future, and very pleasing to see the team’s faith in the powerful benefits of the HPS offering.”
“Working together we will be able to optimize hull performance and help Wallenius Wilhelmsen fully comply with global regulations and targets while meeting its own stringent environmental objectives. This is a high-quality solution for a high-quality shipping company,” added Gunhild Tveitan, business development manager Scandinavia.
Fouling is a key contributor to the spread of invasive species across marine ecosystems and a major cause of hull inefficiency, leading to increased fuel consumption and emissions. Studies have suggested that the fuel consumption of the world fleet could be reduced by up to 20% if all vessels were kept fouling free.
“As a company, we are focused on enhancing sustainability and reducing the environmental impact of our operations – maintaining clean hulls is a key enabler for that,” said Geir Fagerheim, SVP Marine Operations, Wallenius Wilhelmsen. “With HPS we can not only achieve this objective, but we also open a digital window onto how hull condition affects fleet-wide performance, efficiency and emissions, creating a culture of transparency and accountability.” Read more
Heat resistant paint and coatings are special coating products designed to withstand high temperatures while providing protection against corrosion. They are developed to protect the surfaces that are exposed to rapid temperature changes and high heat. High resistant paint can tolerate temperatures up to 700 °C and above.
Heat resistant paint could either be an epoxy phenolic, silicone, epoxy novolac, silicone, or a more specialized multi-polymeric matrix depending on the level of temperature resistance required. Some of the applications of heat resistant paint are as follows
Coating of boilers
Coating of steam pipes
Coating of Chimneys to reduces the chances of fires due to overheating.
It is used in the engine room
Used in power, chemical plant and in refineries
Automotive engine, fan, radiator, and exhaust system
Coating of Boilers
Corrosion Under Insulation
Building construction etc
Types of heat resistant paint
Multi polymeric paints (epoxy or silicone based)
This could be Single or two components, water- or solvent-based. It is formulated to provide resistance to high heat when applied at new construction, on-site and as a maintenance coating. It is usually the more silicone, the higher the temperature resistance, for medium to high temperature protection for example on machinery parts.
High temperature powder paint The powders are usually epoxy and silicone-based (like the liquid paints), and silicone-based powders perform better at higher heats. These have the benefit of being VOC free and having a wide range of gloss and colour finishes.
Thermal spray and metal additive coatings These coatings are particularly used for corrosion protection combined with heat resistance. Thermal sprayed aluminium is particularly usedfor CUI prevention in onshore and offshore platforms and processing plants. Metal pigments are often used as stabilisers for temperatures above 400°C.
Heat resistant ceramic paint The heat resistance properties of ceramic coating are well known, and some of the highest heat coatings available are ceramics. They also provide corrosion protection and chemical resistance and a hard finish. With high temperature ceramic coating insulation and the metal under it can also be protected.
Factors to Consider When Selecting a High Temperature Coating
The temperature range – One of the most common reasons for failure is expecting these coatings to perform outside of the temperature range they were manufactured to tolerate. Each coating type has a specific temperature range, and outside it the functionality and efficacy fails. Make sure not to understate the maximum temperature. Knowing the typical operating temperature – as well as any spikes – will help you determine which coatings should be applied.
Selecting a coating that is not only rated to your highest temperature, but colour stable to that temperature is important for a few reasons. it ensures that the painted equipment stays the color that you selected. It can also promote safety. Colour coded hot pipes in refineries and chemical processing facilities must maintain their color purity. Paint colours can signify the pipe temperature, or the cargo inside. For this reason, selecting a color stable high temp coating becomes a must.
Choose coating products that are specially formulated for your need – If you are choosing a coating to combat CUI, that coating needs to be specially formulated for the purpose. It needs corrosion resistance, but it also needs to be able to be applied to hot substrates and deal with boiling water exposure.
Application characteristics – Application characteristics should be a major consideration when selecting your high temp paint. These coatings require a relatively thin film in order to stay flexible at high temperatures without cracking. Thin films can be very hard to achieve, especially in a maintenance painting situation. Thicker film options like our (2-16 mils DFT) are generally preferable.
Thick film or high build high temp coatings must exhibit superior flexibility to allow for higher film builds in extreme temperatures. High build capabilities are desired because they allow for a larger barrier from the elements, and a longer service life. Additionally, high build capabilities allow for greater flexibility during the application process.
We deal on all leading brands of heat resistant paint and coatings. Call us at Chemic Integrated Services for all heat resistant requirement.
Welding electrode is a metallic rod, coated with flux and comes in varying lengths and radius. A current is fed through this rod when connected to a welding machine which helps to join two pieces of metal together. Welding electrode is used to sustain the welding arc and to provide the filler metal required for the joint to be welded. The flux coating on the electrodes determines how it will act during the actual welding process.
Welding electrode is made up of material with a similar composition to the base metal being welded. An electrode could be either consumable or non-consumable. It is important to choose the right type of welding electrode for your job in order to create clean, strong welds with excellent bead quality and to minimize spatter.
Welding electrode selection
The type of Welding process such as Shielded Metal Arc Welding (SMAW), Gas Metal Arc Welding (GMAW/MIG), Flux Cored Arc Welding (FCAW), Gas Tungsten Arc Gas Welding (GTAW/TIG) is an important factor to look out for in welding electrode selection.
SMAW or stick electrodes are consumable, meaning they become part of the weld, while TIG electrodes are non-consumable as they do not melt and become part of the weld, requiring the use of a welding rod. The MIG welding electrode is a continuously fed wire referred to as wire.
Stick welding electrode selection
Below are some of the factors you should consider when selecting a stick electrode
Base metal type – The first step in choosing an electrode is to determine your base metal composition. Your goal is to match (or closely match) the electrode composition to the base metal type, which will help ensure a strong weld. Thick materials require an electrode with maximum ductility and low hydrogen to prevent weld cracking.Electrodes with AWS classification numbers ending in 15, 16 or 18 provide excellent low–hydrogen properties and good toughness (high impact values) to accommodate for residual stress.
For thin materials, you will need an electrode that produces soft arcs, such as a 6013, Also, smaller diameter electrodes will provide shallow penetration to help prevent burn-through on thinner materials.
You’ll also want to assess the joint design and fit-up. If you’re working on a joint with a tight fit-up or one that is not beveled, use an electrode that provides a digging arc to ensure sufficient penetration, such as an E6010 or E6011. For materials with wide root openings, select an electrode, such as an E6012, that creates a concave weld face suitable for bridging gaps and making groove welds.
Joint fit-up and welding positions – To determine what position(s) a particular electrode is qualified for, refer to the third digit in AWS classification. Here’s how you decipher the qualified electrode position:1 = flat, horizontal, vertical and overhead 2 = flat and horizontal only For example, a 7018 electrode can be used in the flat, horizontal, vertical and overhead positions.
Tensile Strength – To prevent cracking or other weld discontinuities, match the minimum tensile strength of the electrode to the tensile strength of the base metal. You can identify a stick electrode’s tensile strength by referring to the first two digits of the AWS classification printed on the side of the electrode. For example, the number “60” on an E6011 electrode indicates that the filler metal produces a weld bead with a minimum tensile strength of 60,000 psi and, as a result, would work well with a steel of similar tensile strength.
Welding Current – Some electrodes can be used with only AC or DC power sources while other electrodes are compatible with both. To determine the correct current type for a particular electrode, refer to the fourth digit of the AWS classification, which represents the type of coating and type of compatible welding current.
The type of current you use also influences the penetration profile of the resulting weld. For example, a DCEP compatible electrode, such as an E6010 delivers deep penetration and produces an extremely tight arc. It also has the ability to “dig” through rust, oil, paint and dirt.
A DCEN compatible electrode, such as an E6012, provides mild penetration and works well when bridging two joints or welding high speed, high current fillet welds in the horizontal position. An AC compatible electrode, such as an E6013, produces a soft arc with medium penetration and should be used to weld clean, new sheet metal.
Welding electrode naming system
The letters and numbers that are printed on the end of welding electrodes are used in the classification of electrode. Most of the welding electrodes will use the AWS system which stands for “American Welding Society”. There are around 4 different types of classification in use today but most manufacturers tend to stick to the AWS system. It makes senses that if you are about to weld 2 pieces of metal together then you will need to know that you are using the correct welding electrode for the job. The wrong one could end in the joint falling apart.
Electrodes are manufactured for different purposes and welding types and are classified by a five-digit number like E7011-M. Each number and letter corresponds with a piece of information, including recommended welding position, tensile strength and penetration depth.
The “E” in the classification stands for electrode. The American Welding Society (AWS) numbering system can tell a welder quite a bit about a specific stick electrode including what application it works best in and how it should be used to maximize performance. With that in mind, let’s take a look at the system and how it works.
The prefix “E” designates an arc welding electrode. The first two digits of a 4-digit number and the first three digits of 5-digit number indicate minimum tensile strength. For example, E6010 is a 60,000 psi tensile strength electrode while E10018 designates a 100,000 psi tensile strength electrode. The next to last digit indicates position. The “1” designates an all position electrode, “2” is for flat and horizontal positions only; while “4” indicates an electrode that can be used for flat, horizontal, vertical down and overhead. The last 2 digits taken together indicate the type of coating and the correct polarity or current to use. To represent E6010 , E – Electrode, 60 – Tensile strength,1 – position, 10 – Type of coating and current.
Get in touch with our expert team for all welding electrode requirement.
Chemic Integrated services is a leading welding electrode dealer in Nigeria. We trade in various brands of welding electrode which are of global repute and approvals. Some of our brands include Lincoln, Ador, Esab, Hyundai, etc. Our product range comprises of
Stainless steel and Mild Steel Welding Electrodes
Multiple application TIG Welding Wires and MIG Welding Wires
Stainless Steel Flux Cored Wires
Special Application welding electrodes and wires etc.
Our aim as a welding electrode dealer is to ensure quality in everything we sell and build long-term relationships with our customers.
About welding electrode
Welding electrode is as called welding rod. Welding electrode could be either consumable or non-consumable they are metal wires with baked on chemical coatings. The rod is used to sustain the welding arc and to provide the filler metal required for the joint to be welded. Welding electrode is very important in the welding process as they add filler metal to the area that requires welding. It is used as an electrode in some arc welding methods, and it is generally made of the same material as the base material that requires welding.
The first two digits of an electrode indicate the strength of the electrode. This strength is measured in thousands of pounds per square inch (psi). For example, an electrode classified as E80xx has a tensile strength of 80,000 psi. Subtract 13,000 from the electrode tensile strength to determine the approximate minimum yield strength. For example, the E80xx electrode has yield strength of 63,000 psi.
The third digit of the electrode classification determines the appropriate welding positions. Welds are performed in four major positions: flat, horizontal, vertical and overhead. Exx1x electrodes can be welded using all four positions with the vertical position moving up. Exx2x electrodes use only flat and horizontal positioning. Exx4x electrodes may use all positions with the vertical position moving down.
The fourth digit represents the classification type. The classification type states the electrode’s coating, penetration depth and required current type. Penetration depths range includes light, medium or deep. Current types include alternating current (AC), direct current electrode positive (DCEP) and direct current electrode negative (DCEN), though some electrodes use multiple types depending on the type of weld.
Certain electrode classifications include a suffix which identifies any additional requirements or information. Low alloy steel coated electrode requirements differ from the requirements of mild steel coated electrodes. Some common suffixes include M, which signifies military-grade electrodes, and G, which signifies that the electrode has no required chemistry.
Exxon, Chevron Battle it Out in the Permian. The two U.S. shale heavy-hitters both anticipate their Permian production will reach about 1 million barrels of oil per day in the next five years.
But who will fare the best?
Rystad offers five key points:
Drilling activity: Exxon will have to drill about twice as many new wells as Chevron to reach the production goal. As of 2018, Chevron’s unconventional output in the Permian was 75 percent higher than Exxon’s, so Exxon needs to accelerate drilling activity in order to close the gap and even exceed Chevron’s supply by 2025.
Rig programs: Currently Chevron doesn’t plan to ramp up drilling in the Permian as it believes the current program is already optimized with respect to well fundamentals and midstream infrastructure. Exxon, however, believes a large scale ramp-up of its Permian drilling campaign is needed to achieve capital efficiency and generate billions of dollars in cash flow from the region by 2023.
Acreage: Chevron’s legacy land accounts for 1.7 million acres across the Permian Delaware and Permian Midland basins. Exxon currently owns 1.6 million acres in the Permian, including a significant portion attributable to conventional targets in the Central Platform. Chevron has larger upside potential in the Delaware, while Exxon holds more drilling locations in the Midland Basin. Moreover, Chevron’s inventory is expected to deliver an average of five wells per section in Delaware and about six wells per section in Midland, while ExxonMobil will place seven and eight wells per section in each basin, respectively.
Well economics: Chevron achieves exceptionally low costs for each barrel of oil equivalent (boe) produced in both the Texas and New Mexico parts of the Delaware Basin, standing at below $5 per boe. Exxon’s cost comes out slightly higher at $6.30 per boe, still considerably below the average of between $8 and $9 per boe.
Scale: In the Delaware Basin, which is less developed than the Midland, Chevron leads in terms of average pad size as of 2018, on Texas and New Mexico sides. Exxon comes immediately after Chevron on the New Mexico side of the state border, with 3.3 wells per pad last year. In the Midland Basin, Chevron clocks in at about four wells per pad, and thus ranks again among the industry leaders.
Rystad Energy’s head of shale research Artem Abramov said Chevron and Exxon will leave all well-established shale producers behind.
“While Chevron is currently leading in terms of well productivity, economics and total Permian output, ExxonMobil is expected to continue to close the gap in the years to come,” he said. “Higher investments coupled with potential well performance improvements are likely to give an edge to ExxonMobil from 2020 to 2030. On the other hand, a larger acreage position with considerable upside potential provides Chevron with an opportunity to continue to grow post 2030.” Click here to read more.
An international arbitration tribunal has unanimously ordered the government of Venezuela to pay ConocoPhillips $8.7 billion.
The company has revealed that an international arbitration tribunal has unanimously ordered the government of Venezuela to pay the company $8.7 billion.
The compensation is for the government’s “unlawful expropriation of the company investments in Venezuela in 2007, plus interest,” said in a statement posted on its website.
In the statement, the company said the tribunal ruled in 2013 that the expropriation of ConocoPhillips’ “substantial” investments in the Hamaca and Petrozuata heavy crude oil projects and the offshore Corocoro development project “violated international law”.
The timing and manner of compensation collection “remain to be determined,” ConocoPhillips said in the statement.
“We welcome the International Centre for Settlement of Investment Disputes tribunal’s decision, which upholds the principle that governments cannot unlawfully expropriate private investments without paying compensation,” Kelly B. Rose, senior vice president, legal, general counsel and corporate Secretary of the company, said in a statement posted on the company’s website.
In April 2018, in a separate and independent legal action, an international arbitration tribunal, constituted under the rules of the International Chamber of Commerce (ICC), awarded ConocoPhillips approximately $2 billion from Petróleos de Venezuela, S.A. (PDVSA) and two of its subsidiaries.
In August 2018, the oil giant announced that it entered into a settlement agreement with PDVSA to recover the full amount owed under that award. It also has a pending contractual ICC arbitration against PDVSA related to the Corocoro project.
ConocoPhillips is the world’s largest independent exploration and production company based on production and proved reserves, according to its website.
Headquartered in Houston, Texas, ConocoPhillips has operations and activities in 16 countries. Back in January, the company reported 2018 earnings of $6.3 billion. ConocoPhillips recorded a full-year 2017 net loss of $0.9 billion. Click on the link for more details.
Contact our technical team at Chemic Integrated Services for oil and gas products and services. We are procurement specialist and manufacturer’s representative in the Nigeria market and beyond.
Battling Corrosion: How Technology Has Changed the Fight to Protect Pipelines
Fighting corrosion has been a key part of pipeline integrity management for almost 50 years. While the threats are fairly well known, technology has changed how the industry assesses and addresses corrosion control.
Pipeline companies have more data about their assets than ever before. How they use that data has a major impact on managing corrosion and extending the life cycle of pipelines and other facilities.
Not only must operators keep up with the staggering amount of data they’re collecting through integrity management assessments, but they also must keep ahead of increasing governmental regulations that continually move the goal posts for operational excellence.
Better technology and increased industry standards are all about improving safety, according to Drew Hevle, corrosion control manager at Kinder Morgan.
“Certainly, the concerns about protecting people, the public and environment are ever increasing,” Hevle says. “Standards for safety and the environment continue to raise the bar. Regulations are more and more stringent and broader. New technology and capabilities that we didn’t have in the past have been applied to continue to improve the safety of pipelines.”
One of the key considerations for improving corrosion control processes is the concern over aging infrastructure, according to Dirk van Oostendorp, director of engineering services for Corrpro.
“There are some very old pipelines still in service that were built in the mid-1950s,” van Oostendorp says. “Typically, when you design and build a pipeline, you design it to last for 25 years. Many of our pipelines are well beyond their design life. If you tried to replace them all, the cost would be astronomical. And there are no guarantees you’re going to get the permits to install a pipeline in the same location. Everyone is very focused on what I call geriatric rehabilitation to keep these pipelines operational.”
Corrosion engineers have access to vast amounts of data that helps them understand the condition of a pipeline. Pipeline operators must integrate that data to make informed decisions about their assets.
Understanding the Threats
Pipeline corrosion is caused by a number of different factors. The presence of water in a pipeline, soil conditions, proximity of power lines, certain microbes, external damage, impurities in the pipeline — all of these are major causes of corrosion.
The first line of defense is the pipeline coating, applied both externally and internally, to protect against the environment where the pipeline is installed and the material flowing through the pipe. If the coating becomes damaged, there are methods for rehabilitating it as needed.
Cathodic protection (CP) systems guard against exterior pipeline corrosion by applying anodes, rectifiers and DC currents to redirect corrosion to an anode that can be replaced.
AC mitigation protects pipelines that are built in parallel to overhead power lines. There are a number of ways to protect pipelines against AC interference, including fault shielding, gradient control mats, grounding systems and gradient control wire.
Microbially influenced corrosion (MIC) can be assessed using non-destructive evaluation (NDE) and compared to existing corrosion data. Proper mitigation is determined on a case-by-case basis, once the characteristics of the microorganisms present in the pipeline are determined.
External damage, from most commonly third-party strikes or installation errors, can also lead to corrosion by causing damage to the coating. Stress corrosion cracking (SCC) is another area of concern, caused by a combination of environmental, stress and material factors.
Further methods of corrosion control are based on pipeline integrity management systems, such as inline inspection (ILI), ultrasonic testing (UT), radiographic testing (RT), hydrotesting and other means.
A Mature Market
Corrosion control is “a fairly mature market,” Hevle says, referring to the knowledge of threats and the understanding of longstanding regulations.
“The initial regulations relating to pipeline corrosion came out in 1971, and many of them have not been changed since then,” he says. “There’s not a lot new in that regard. What is new is the availability of data from integrity assessments we can use to prioritize efforts to identify threats, to understand them better and where we need to apply additional resources for corrosion monitoring and mitigation.”
Corrosion threats are also pretty much the same as they have been for 40 years, Hevle says, explaining that a relatively new threat like AC corrosion came to light in the 1980s.
“Those threats are fairly well understood now,” he says. “We’ve had consensus on industry standards on how to address those concerns and regulations put in place to address them.”
However, a major change is coming to the industry. Hevle says the pipeline industry is awaiting sweeping revisions to natural gas safety regulations later this year. Known as the “Gas Mega Rule,” the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA) is finalizing a set of rules that could double the number of pages of regulations that impact natural gas infrastructure.
According to a report from corrosion protection provider Matcor Inc., PHMSA’s proposed rulemaking will be broken up into three parts. The first section will address the expansion of risk assessment and maximum allowable operating pressure (MAOP) requirements to include areas in non-High Consequence Areas (HCAs) and moderate consequence areas (MCAs). Another part of the rulemaking will focus on the expansion of integrity management program regulations, including corrosion control to gathering lines and other previously non-regulated lines. And finally, the rulemaking is expected to focus on reporting requirements, safety regulations and definitions to include expanding into related gas facilities associated with pipeline systems.
“The trend of increasing regulations just reflects society’s expectations of higher and higher levels of safety,” Hevle says. “In the same way that public expectations are increasing, we also have a better-informed public than ever before because of the information available on the internet and social media.”
For an operator, the governmental regulations should act as a baseline for the minimum required corrosion protection, adds John Strong, technical field specialist for Polyguard.
“If an operator discovers corrosion on a pipeline the government regulations give a timeline for when a remediation is due,” Strong says. “A prudent operator will take this corrosion discovery as an opportunity to learn why it occurred. While the government regulations do drive most of the corrosion work performed on pipelines, it is also in the operators’ best interest to have a proactive stance when it comes to corrosion protection.”
In addition to regulatory considerations, corrosion protection providers are being asked to improve efficiency, says Keith Nevils, product director for pipeline services at Corrpro.
“There’s an impetus to do things faster or do it for less money,” he says. “It’s driving in both directions. On the efficiency and quality side, data collection is a big one. Because operators have to report to PHMSA on a regular basis, can you imagine if you had a binder full of papers that you had to look at every time? That’s a terrible way to manage your data, but still a number of companies are doing it that way.”
Lots of Data
New technology has made it possible to collect vast amounts of data about pipeline conditions, but technology has also made it easier to ensure data is accurate, Nevils says. For instance, a voltage meter can be outfitted with Bluetooth to enable a tablet computer to automatically import and view measurements. Technology allows electronic data collection to be pushed into a repository to find at any time.
“We may get some pushback in the industry with a resistance to technology,” Nevils says. “But more and more, we’re finding people who embrace technology.”
Hevle agrees, explaining how Kinder Morgan uses technology to build a robust database on its pipeline systems.
“We use a GIS system now that incorporates data not only from pipeline construction material, but from monitoring corrosion mitigation, as well as gas quality information from other sources,” Hevle says. “We have soils information and satellite photos that we can overlay in our GIS to show transmission power lines that we use to identify where we may have AC corrosion threats.”
Hevle describes how his job has changed since he entered the pipeline industry because of technology, noting that it has become a lot more computer-focused over the years.
“When I first started, it was a question of how to find information to make educated decisions,” he says. “Now we have to find a way to manage all the data we have to make those decisions. We have the opposite problem. We have more data than a person can process. We’re looking at different ways to present the data graphically and automate processes using algorithms to process multiple different components.”
Automating data collection not only improves the accuracy of the information, it also improves efficiency and allows operators to make decisions quicker, according to Alasdair Stoddart, director of pipeline integrity management at Corrpro.
“Information collected from an asset is moving from having a technician in the field and data being collected with pen and paper, and then having the information typed into a document, to instead using electronic data capture,” Stoddart says. “That’s becoming a more integral part of asset management. As that trend continues, what we find is that the accuracy of the data becomes hugely improved. We find that the efficiency of gathering information is improved, and the real-time nature of the data is improved to the point where the asset owner has access to the information much faster than in the past.”
By automating data collection and getting the information quicker, Stoddart explains that the pipeline industry is able to move to a risk-based decision-making model, rather than time-based decision making.
Moving from prescriptive corrosion surveys to risk-based inspection (RBI) and quantitative risk assessment (QRA) driven intervals is where the industry should be moving, according to Daniel Ersoy, executive director of R&D at GTI. This is also well-aligned with the principles of distribution integrity management plans (DIMP) as required by federal and state regulations.
Changes to Come
While the pipeline corrosion market is mature, there are coming changes that could impact the industry in the next few years in terms of how corrosion control providers work with operators and how new technology will be implemented.
Stoddart sees pipeline operators looking to service providers to be stronger partners in the fight against corrosion.
“We’re looking to become an integrity partner with our customers, being more of a full suite provider from pipeline commissioning to monitoring thereafter,” he says. “Asset owners are looking for integrity companies to provide more guidance. Let the experts do the role they were designed to do more effectively.”
Nevils believes that there is still a tremendous amount of technology that can be introduced to the corrosion control market.
“What we’re doing with data collection, we’re like Google in the early days,” he says. “We’re building the repository for data, and now we need to do something with it, so we can become more predictive. That way we can get in front of the problem, instead of being behind.”
As computing power increases, Nevils says that the pipeline industry will be able to better understand the massive amounts of data it has and will continue to collect about the condition of its assets.
Ersoy agrees, noting how the Internet of Things (IoT) could impact the industry.
“IoT and other communication technology and protocols have the potential to change how we collect, pre-process, communicate and post-process corrosion-related data to make engineering, risk and integrity management decisions,” Ersoy says. “This might make it possible, especially for surface accessible locations, to have sensors for temperature, humidity and moisture, cathodic protection and pipe-to-soil levels, pH, conductivity, resistivity, etc., that are all real-time and communicated to a central database to enable more accurate risk calculations.”
Ersoy also believes that coatings will continue to improve.
“Interest is growing in novel and nano-based coatings for internal corrosion and flow improvement, as well as external self-healing and active passivation and sacrificial protection systems,” he says. “These coatings hold promise to provide improved corrosion resistance and system performance, while simultaneously lowering maintenance and repair costs.”
As the war against pipeline corrosion wages on, technology has changed and will continue to improve safety and integrity throughout the industry. Click on this link to read more on this topic.
Antifouling coating product has been lunched by Coatings manufacturer Hempel. This antifouling has been designed to protect the hull from fouling throughout service intervals of up to 60 months. The new antifouling coating is suitable for all vessel types and all water temperatures.
Atlantic+ incorporates a biocide package and binder system. This ensures progressive and controlled self-polishing from the moment the hull hits the water and for up to 60 months thereafter. The new coating is reinforced with Hempel’s patented microfibre technology at a higher level of the company’s strongest cargo hold coating – Hempadur Ultra Strength Fibre.
The science behind the microfibre technology involves introducing an internal skeleton of fibres into the paint to enhance its mechanical strength – in the same way that steel rods can be inserted into concrete to reinforce a physical structure. Strengthening the antifouling coating in this way means ensuring protection from fouling on areas exposed to impact and abrasion; improving overcoatibility; reducing the areas to blast; and ultimately decreases the costs for the ship´s dry docking.
Commenting on the new coating, Hempel’s Group Product Manager, Marine Group Product & Portfolio, Davide Ippolito, said:
“Ever mindful of the operational and financial pressures on shipowners and operators, we are keen to continue to broaden our portfolio of hull coatings to ensure we are delivering a range of solutions to suit every customer. Atlantic+ is a mid-market coating that enables shipowners to benefit from a high-quality, high performing antifouling coating with superior mechanical strength. We’ve ensured our new product is easy to apply and that it provides protection for up to 60 months in a wide range of conditions offering high operational flexibility.”
Atlantic+ incorporates ingredients that enhance antifouling performance and provide effective self-polishing and smoothing characteristics. Its binder technology and use of biocides ensures consistent, progressive and controlled polishing in all trading conditions.
Global Zinc Rich Primer Market 2023 report offers detailed impression of the competitive development and regulatory framework of the market. This will deal readers a clear understanding of the state of opposition, threats, major forecasts, and the major principles, procedures, tactics, and schemes impacting the market. The report summarizes the future market trends based on manufacture technology. The report considers all the major aspect affecting to business stability, basics concepts followed to recognize the business strategies. Global Zinc Rich Primer market Production, Supply, Market has boosted the global economy strongly since last period. The market has been providing economic stability as well as stimulating development in its peer and parent markets. The report is a complete analysis which discovers the significant and ongoing journey of Zinc Rich Primer Production, Supply, and market along with market forecast up to 2023. The report covers the extensive assessment of major Zinc Rich Primer Production, Supply, market participants, strategic planning, and technological growths in the market.
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The latest research suggests body-paint that offers effective protection against blood-sucking insects.
The new study, published this week in the journal Royal Society Open Science, confirms what many indigenous groups realized long ago. Body painting among indigenous people is more common in areas where horseflies, mosquitoes and tsetse flies are present.
Researchers at Lund University used a series of human mannequins to test the effects of body paint on the behavior of blood-sucking insects. The plain brown plastic model attracted ten times more horseflies than the model painted black with white stripes. The beige model attracted twice as many blood-suckers.
“Body-painting began long before humans started to wear clothes. There are archaeological finds that include markings on the walls of caves where Neanderthals lived,” Susanne Akesson, professor in the biology department at at Lund University in Sweden, said in a news release. “They suggest that they had been body-painted with earth pigments such as ochre.”
Insect glue helped researchers track the number of blood-suckers attracted to the three models.
Scientists also tested whether the models’ positioning affected their allure. Models standing up attracted more females, while models lying down attracted both sexes.
“These results are in line with previous experiments in which we showed that males gravitate towards water in order to drink and land on surfaces that reflect horizontal, linear polarized light, such as signals from a water surface,” Akesson said. “Females that bite and suck blood from host animals respond to the same signals as the males, but also to light signals from in the vertical plane, such as the standing models.” For more details click here