Ed Hall reveals how a novel solution is helping in the fight against corrosion

Corrosion is one of the biggest unforseen costs that oil & gas operators face and it is cited as one of the major issues for pipeline failure in oil & gas and chemical process plants. The Worldwide Corrosion Authority, NACE, estimates the cost of corrosion is more than US$2.5 trillion, which is roughly 3.4% of the world’s gross domestic product (GDP).

Predominantly influenced by the surrounding environment, corrosion can form quickly and un-noticed around the connection of a pipe, metal contact points, within the crevices of bolt heads and nuts, in steel to concrete interfaces or between a flange face and valve fitting.

Without routine maintenance corrosion can lead to serious safety risks and environmental hazards, such as leaks, which incur significant penalties. Within the pipeline, failure to identify and resolve corrosion will ultimately lead to a failure to operate.

The costs to shutdown a pipeline due to corrosion would be considerable in both material, labour and downtime. Simply cutting away corroded bolts is a task that can add two to three days to maintenance. In these situations a preventative approach is best adopted ideally before signs of degradation occur, but at least when corrosion is in early stages and equipment is still fully operable.

Pipe support corrosion protection and integrity maintenance solutions - Some examples from the field

It is well documented that pipe supports are the second biggest issue of corrosion on external piping after corrosion under insulation (CUI) in a wide range of industrial plants and offshore topside process piping. The primary location for corrosion is at the 6 o’clock position where it is difficult to identify without close visual inspection or through the use of costly inspection equipment. It is not always safe and will often require detailed analysis prior to lifting for inspection purposes due to the design of some clamps and supports that could result in a risk of damage and or product release, resulting in safety issues.

50-60% of all pipe corrosion leaks are caused by contact point corrosion as found with corrosion under pipe supports (CUPS).

What is a pipe support?

A pipe support is usually made out of steel, providing a framework of a certain distance from the ground to support and distribute the weight of suspended pipes. They typically comprise of structural steel such as I-beam, angle and channel section. These pipes are normally secured to the member using u-bolts. Also found in such facilities are either half or full saddle clamps, and welded supports/guides which allow movement of the pipe within the support, but they also invite corrosion. These pipes can be carrying a variety of substances; water, gas, oil, chemicals, petrol, saltwater – anything that travels through a pipe.

The environment is typically aggressive from a corrosion standpoint, with exposure to water, chemicals, salt, humidity and abrasion often present. Due to the shape and contours of the pipe support, these corrosion accelerants are easily trapped between the pipe and the support, allowing corrosion to develop. Since they are so difficult to visually inspect it is often too late to identify when the crevice corrosion has begun.
 
Many common solutions used to eliminate this problem can actually aggravate the situation as they still allow for the accelerants to sit against the live pipework. Liners and rubber pads, fibreglass pads to name a few have all failed, as they do not eliminate the water and corrosion continues.

Many solutions that are available in the marketplace require a shutdown to install the solution and even then only when they are replacing pipework, such as the use of half round plastic rods which minimise the contact point of metal to metal. In a best-case scenario these solutions are fitted at the outset of pipe installation.  

Even during a shutdown, if the operator is not intending to replace the pipework, they are reluctant to remove u-bolts/hangers/clamps, and lift the pipe to install these, as they do not want to risk the possibility of damage to the pipework.

The ultimate solution

Oxifree has developed an innovative coating encapsulation, TM198. This thermoplastic coating is organic and provides a protection solution that halts, mitigates and eliminates (further) corrosion to pipe supports and other complex structure interfaces.

The coating is melted down from a solid resin (in the supply unit) and applied using a heated hose and gun to fit the contours of any complex component. A key feature of the TM198 encapsulation system is the non-adherence to the substrate, along with self-lubricating properties, which allows any pipework that needs to move within the clamp to also move within the TM198. This makes it suitable for a wide range of piping where pipes expand and contract or subject to vibration, even on FPSOs. Indeed, the coating is now being used globally to halt the issue of CUPS for oil and gas majors.

Whereas other solutions require a shutdown and take time to install, the Oxifree coating can be applied to live pipework and provides protection immediately, as it cools on impact, saving considerable downtime cost, and no disruption to production. This makes it complementary to (applied alongside and/or over) other protective solutions.  

Once the pipe, saddle and clamp are encapsulated, the surface within is protected from moisture and oxygen protecting it from further degradation.

This novel solution is only applied once and will provide many years of protection in the harshest of environments. Should inspection be required this can be done through the coating with the use of NDT/ANDT inspection techniques (such as UT) or a small area cut away from the coating for visual inspection and can simply be refilled/resealed.

The oil & gas industry is still facing the challenge to reduce unnecessary expenditure and make critical savings to maintenance, while increasing safety and reducing ecological impact. Extending asset lifespan without operational shutdown is the fundamental way forward. Creating a culture of prevention with new technologies will be the ultimate solution.

Smart tech to deliver fastest upstream start-up for Aasta Hansteen’s first gas production

Innovative technology is estimated to save 40 days in the commissioning phase by reducing manual interventions by 98%.

ABB is set to deliver what it believes to be the world’s fastest start-up when Equinor’s Aasta Hansteen gas field begins operating and produces its first gas. The firm is in the final phase of providing a suite of ABB Ability digital technologies for Aasta Hansteen, which is located in 1,300m of water in the Vøring area of the Norwegian Sea, 300km from land.

Part of the challenge for ABB was to make the first gas start-up process as quick and efficient as possible. For this, it needed to reduce a sequence of over 1,000 manual interventions to as few as possible. The outcome is a series of buttons that are as simple as starting a car.

“Our teams went through the start-up steps, identified and defined obstacles that needed to be improved, then used our ABB Ability System 800xA simulator to do a virtual start-up of the plant,” explains Per Erik Holsten, MD for ABB Oil, Gas and Chemicals. “At this stage we made a lot of improvements for starting up and operating the plant. Through automating much of the process we managed to reduce a complex set of manual interventions to just 20, which means we are all set to deliver what we believe to be the world’s fastest start-up at first gas.”

The company estimates it saved about 40 days (or nearly 2,700 man-hours) in the commissioning phase of the project by using the simulator to identify and improve 57 areas in the start-up.

The simulator is a solution that minimises risk and reduces the occurrence of unplanned shutdowns, while improving safety, productivity and energy savings. It has a control system that is disconnected from the physical process and is instead simulated by a dynamic process model. By seamlessly extending the distributed control system (DCS), the ABB system provides the same look and feel as the core functional areas. It is a scalable solution in system size, functionality and control system connectivity and is available in three editions: Basic, Premium and Professional.

“In the operation of oil and gas projects there are lots of different automation and instrument competencies and disciplines required for the project to run smoothly,” Holsten says. “In upstream greenfield sites such as Aasta Hansteen, ABB is one of the few companies that is sufficiently skilled and resourced to connect the different parts of the jigsaw together to provide a truly connected plant. Aasta Hansteen is a great example of how it is possible to do just that, while making the start-up and operation of the plant more efficient.”

The solution is part of a much bigger suite of digital technologies being implemented by ABB at Aasta Hansteen. These include a condition monitoring system to monitor more than 100,000 maintenance conditions from more than 4,000 pieces of equipment, tools for alarm management and alarm rationalisation, delivery of several safety critical applications, data storage solution to store all alarms and events easily, and third-party system integration of essential data traffic.

An advanced anti-corrosion coating is being used successfully on two North Sea offshore platforms

In a collaborative effort designed to improve vital protection of offshore assets, the Oil & Gas Technology Centre (OGTC) in Aberdeen, UK is successfully conducting trials of an advanced anti-corrosion coating on two North Sea offshore platforms.

The mission of the OGTC, which is jointly funded by the UK, Scottish and Aberdeen governments, is to establish a culture of innovation that will consolidate Aberdeen and North-East Scotland’s position as a global hub for oil and gas technology and innovation.

The challenge, however, is that the UK’s North Sea is one of the most brutal climates in the world. Often ice cold and windswept, the rigs in the North Sea face a constant corrosive onslaught of waves and salt spray.
 
Traditional coatings simply cannot withstand the environment. The cost of maintenance on a rig can be up to 100 times as expensive as land-based maintenance because crews and supplies often have to be helicoptered out to the site, so when coatings fail it costs the asset owner enormous amounts of money.

After extensive research, OGTC identified a spray-applied inorganic coating called EonCoat, from the USA-based company of the same name, as a method of delivering long term protection for the offshore assets. The anti-corrosive coating represents a new category of tough, chemically bonded phosphate ceramics (CBPCs) that can stop corrosion, ease application and reduce offshore platform production downtime even in humid, storm or monsoon-susceptible conditions.

OGTC worked with EonCoat’s UK distributor and applicator, SPi Performance Coatings, to implement two trial programmes. With OGTC’s vision and sponsorship, SPi applied EonCoat to a Total E&P platform and a Nexen platform, each of which is located on the UK continental shelf in the North Sea. Total is a global integrated energy producer and provider, and a leading international oil and gas company, with operations in more than 130 countries. Meanwhile Nexen is an upstream oil and gas company responsibly developing energy resources in the UK North Sea, offshore West Africa, the USA and Western Canada.

Total E&P trial

SPi applicators, along with EonCoat material and equipment, were helicoptered to Total’s Elgin ‘A’ Wellhead platform on December 17, 2017. The coating was applied to areas of the platform’s lower deck that were suffering from severe corrosion, and a topcoat was added for aesthetics.  

Surface preparation for the trial was carried out by Muehlhan, a global provider of surface protection and industrial services with operations in shipping, oil and gas, renewables and industry/infrastructure segments.

In the trial area, the existing coating system was completely removed from structural steel tubulars and flat plate. The structure was power washed and degreased to remove contaminants.  All tubulars were blasted to SA2.5, and flat plate mechanically prepped to ST3.  

Although rust rashing was visible on areas prior to spray application of the anti-corrosion coating, this was deemed acceptable due to the coating’s particular properties. It can be applied to a damp substrate with rust rashing/flash rusting, and high salt levels do not degrade the coating, which reduces surface preparation requirements.  

The coating can cure in a single coat 15 minutes after application, depending on climatic conditions, which expedites completion, compared to traditional coatings, which require extensive drying time between coats.

In contrast to traditional coatings, which only form a physical barrier to corrosion until breached, EonCoat chemically bonds with bare substrate surfaces, providing an iron magnesium phosphate layer that prevents steel corrosion. This process provides a very thin layer (about 2 microns) of permanent protection. A second layer – a tough ceramic outer shell – provides further protection, and also acts as a reservoir to re-phosphate the steel if needed. This ensures the alloy layer remains intact, and allows it to “self heal” if it is ever breached by mechanical damage.

During this ongoing trial, testing has been done via cross cuts of about 6-8in in length down to the substrate to provide evidence of EonCoat’s self-healing properties.

Nexen trial

After the early success of the Total E&P trial, a second offshore trial is now being conducted. SPi applicators, as well as EonCoat material and equipment, were helicoptered to Nexen’s Buzzard platform on June 18, 2018.
 
After Stork, a Fluor company and global provider of integrated operations, maintenance, modification and asset integrity solutions, assisted with fabric maintenance and surface preparation, SPi applied the anti-corrosion coating to platform areas suffering from severe corrosion.  

Although results from this second trial are still under consideration, they look extremely promising.  

“As oil and gas E&P companies look to combat offshore asset corrosion, extend safe production and reduce the need for costly maintenance and downtime, we look forward to working with OGTC, Total, Nexen, Muehlhan, Stork and other platform owner/operators in the North Sea,” concludes Merrick Alpert, president of EonCoat.

Yves Marinoff describes how a chemical injection package enables MEG injection for extraordinary requirements on vibrations and noise emissions

The thirst for the coveted raw product of natural gas remains unquenched, despite the crisis in oil and gas. Each year, the global quantity of drilling platforms increases – their number has gone up by 25% in just the past seven years alone. In the course of this, locations in coastal regions or in the vicinity of animal nesting areas have also been developed. As a result, the pressure on manufacturers of platform components to adapt their products to environmental demands is on the rise.

These manufacturers must ensure a safe process without disturbances while at the same time providing for the greatest possible protection of people and nature. This requires a departure from standard solutions towards an increasingly flexible product design, one that takes governmental regulations, standards and customer specifications into account - all of which are currently rising greatly in stringency. For this reason, Lewa relies upon intensive project management and excellently trained engineers for its chemical injection packages, to optimise the customised design engineering with regard to factors such as noise emissions and vibrations, as well as the prevention of leaks.

From the date of their discovery in 1811, gas hydrates were overlooked for nearly 100 years after as having been only a “chemical curiosity” – until gaining relevance at the beginning of the 20th century as the result of ice-like entities causing pipelines to break down. In the meantime, this problem was met with the injection of various substances – what are referred to as inhibitors. Monoethylene glycol (MEG) is among them. This organic compound has the benefit that it is not only suitable for the prevention of hydrate formation, but also for gas drying. Furthermore, MEG can for the most part be reclaimed from the process, thus being capable of being reused. Not only does this help to preserve the environment, it also lowers the necessity of transporting the chemical to drilling platforms.

Tried-and-tested system in customised design variations

Due to the two MEG application options, it can be used on an oil rig for two components. For one, it is intermittently injected into the borehole top between the upper main valve and the throttle valve to prevent the formation of hydrates. For another, an injection into the cooler of the gas export compressor for the purpose of gas drying is possible. The process is usually carried out at low flow rates by means of diaphragm pumps – at large quantities by means of plunger pumps – that are installed with tanks, piping and instrumentation, all the way to integrated chemical injection packages, exemplified by Lewa. Among other advantages, this has the benefit of being able to take the interactions between individual components into account in the course of an overall optimisation effort.

Whereas the process planning is the responsibility of the specific engineering company, it is the manufacturer who needs to undertake the detailed engineering in accordance with the tenders. The difficulty here is to bring the often highly complex, necessary standards – for example, in relation to environmental protection and operating safety – into accord with the directives and laws that are applicable at the location of use, as well as with customer specifications. In most cases, engineering solutions must be found that diverge from customary solutions. For this purpose, Lewa employs engineers from various disciplines such as hydraulic systems engineering, mechanical engineering and electrical engineering, who contribute to the evolution with their expertise, thus being able to react with flexibility to the most diverse regional conditions.

Keeping negative influence on the environment at a minimum

Most importantly, the harsh sea environment makes special designs necessary. The extremely salty atmosphere makes the use of corrosion-protected materials essential. This is why the company uses materials such as stainless steels for production, in special cases also using duplex or super duplex stainless steels. Owing to the limited space available on an offshore oil rig, it is mandatory that all components such as the pump and fittings are designed to be as compact as possible while simultaneously being conveniently operable.

Furthermore, the system should have as little of a negative influence on life and work quality, as well as on the environment, as possible. This can be achieved by the reduction of noise emissions, which in some circumstances are carried on through structure-borne sound, as well as the reduction of vibrations. One customer desired an especially quiet package. For this purpose, Lewa carried out a corresponding study and searched for possibilities relating to acoustic decoupling. Finally, vibration mats in combination with noise hoods were used. As such, sound emission was lowered from 93dB to 75dB.

In addition, for the minimisation of pressure pulsations, the system was submitted to an evaluation in accordance with API 674 Approach 2.

Prevention of leaks

Since MEG is toxic, the highest requirements are placed on process safety and the absence of faults when handling the substance. For this reason, diaphragm pumps are especially well suited. They are hermetically tight and do not tend toward leakage. Occasionally, however, plunger pumps may be required if, for various reasons, diaphragm pumps cannot be employed or in the event of large flow rates. These are only able to be dynamically sealed by means of packings, which is why special precautions need to be taken in such cases to prevent leaks. For example, in having built a system in accordance with the EU Pressure Equipment Directive (DGRL) for one customer in particular, the company deployed a special leak monitoring system alongside a leakage pan together with outlet drainage in a closed drain system: since commercially available flow meters reach their limits in quantities that are so relatively small, the manufacturer determined it was better to go with measurement using radar.

A reduction in maintenance effort also contributes to an increase in process safety. This is why Lewa skids are fully automatic and mechanically redundant, designed for very long operational durations while featuring a fully monitored leakage system. Moreover, high-quality fittings and instruments provide support. Some of these have self-diagnostic systems available. Thus, work that is necessary is reduced to a minimum.

Due to the wide variety of requirements – both those stipulated by the client and those laid down by law – Lewa relies on detailed planning and administration by its project management department, which, for example, takes over administrative tasks such as the coordination of subcontractors, progress supervision as well as documentation for the oil and gas industry.

Yves Marinoff is with Lewa

A laboratory hoping to guarantee an increase of 22 billion barrels of oil in Brazil’s reserves has opened at Ilha do Fundão, in Rio’s Northern Zone. The Advanced Petroleum Recovery Laboratory, inaugurated by Coppe, a research unit of the Federal University of Rio de Janeiro (UFRJ), is ready to produce technology that will allow the country to expand its oil production, extracting more resources from the already well exploited reserves.

In the new laboratory, which received investments of R$ 107 million from Shell and R$ 10 million from Petrobras, research will be carried out with the objective of investigating and developing advanced recovery techniques applicable to Brazilian pre-salt carbonate rocks. This is a new area of research, whose results could represent billions of dollars in royalties and new investments in Brazil.

According to data from the National Petroleum Agency (ANP), the oil recovery factor in Brazil is 21%. According to the professor of Coppe’s Civil Engineering Program, Paulo Couto, coordinator of the laboratory, an increase of only 1% in the rate of recovery of Brazilian rocks could represent US$ 11 billion in royalties, generating an increase in reserves and new investments estimated in US$ 16 billion.

According to Couto, the equipment purchased for the laboratory can operate any fluids from reservoirs located at great depths, under 700 times atmospheric pressure and up to 150ºC. “We have unique equipment, a porous media flow greenhouse, equipped with an x-ray scanner, which will allow dynamic images at high pressure and a high temperature of oil flow in carbonate rocks. A unique dataset in the world, that does not exist in the literature, and the UFRJ and the Heriot-Watt University stand out as pioneers in this field”, he said, highlighting the partnership with the Scottish institution.

Bengt Löfstedt reviews the ‘what, where and how’ of gas monitoring at refineries

Gas concentration monitoring at refineries can be of importance for safety reasons, but it’s also essential to control production quality, to minimise losses and thereby production costs, and to meet environmental objectives, potentially with reduced pollution and improved health as results.

Which gases to monitor depends on the production processes in play, and where the monitoring is to take place. For process control purposes, a range of hydrocarbons such as methane (CH4) and benzene (C6H6) can be of interest, but also for example carbon monoxide (CO), carbon dioxide (CO2), water (H2O), and hydrogen sulphide (H2S). The concentrations can range between 0 and 100%.

Tail gas monitoring, i.e. the emissions of air pollutants at the end of the production processes, might cover the same gases that are of interest for process control. However, the tail gas often undergoes some combustion process, for example in an afterburner, and other types of gases might also be monitored. This can include for example sulphur dioxide (SO2), nitric oxide (NO) and nitrogen dioxide (NO2). The pollutants at this stage are usually measured in parts-per-million (ppm) ranges. Gas monitoring is sometimes combined with flow monitors to yield the total emissions of pollutants in units of weight-per-time. The driving force behind emissions monitoring is often requirements from legislators and environmental authorities, requiring proofs of emissions limits being observed.

A third application area for gas monitoring is surveillance of the ambient air close to the production facility. When done for personal protection, it is often done with wearable monitors of one or a few hazardous gases, such as CO or H2S. If the concentrations approach dangerous levels, often in the ppm range, the monitor can issue an alarm and the wearer can leave the area before being affected by the gas.

Air quality monitoring (AQM) for the general benefit of the staff at the facility or the inhabitants of the neighbourhood is often based on permanently installed AQM stations. This type of monitoring reveals the long-term exposure to air pollution, often in levels of parts-per-billion (ppb). The types of pollutants to monitor are often the same as those found in the production process, including SO2, NO2 (NOx), benzene, and H2S, but other pollutants of concern such as ozone (O3) and particulate matters can also be monitored, while at it. At best, AQM shows pollution levels well below limits set by the legislators. AQM can be initiated by local authorities wishing to monitor and protect the public health, but it can just as well be on initiative from the facility, to (hopefully) show that the air pollution levels are limited and under control.

An AQM station used for general, long-term monitoring can double as an alarm system for accidental releases of air pollutants from the refinery. This allows countermeasures to be taken, at best long before any staff member or neighbour is affected by the release. Further, an AQM station can also be used to substantiate diffuse emissions occurring from leakages in e.g. pipes and valves. In combination with monitoring of wind speed and wind direction, pollutants can be back-tracked to specific source locations, revealing unknown or excess leakages, and ensuring that proper actions can be taken to stop or reduce the emissions.

So, how are the gas concentrations monitored? It depends on gas type and concentration range. However, in most cases, the measurement devices use the optical properties of the gaseous molecules, looking at absorption light. The more absorption of gas-specific wavelengths, the higher concentration of that gas.

Two types of instruments exist: sampling, which uses pumps, tubing and often pre-treatment of small gas volumes before the absorption is measured in an internal cell, and in-situ (“at place”) where the absorption is measured by sending a light beam through the actual gas monitored (“open-path”).

Open-path monitors have several advantages over sampling instruments, in particular for permanent AQM applications. A sampling instrument captures the gas in a single inlet point. If a plume of an emitted gas does not pass that point, the emission will not show. In contrast, the monitoring results from an open-path instrument are average concentrations along the light beam, often several hundred metres long. A series of light beams can form an optical fence around the facility, capturing the plume no matter of its direction.

A single open-path system can often use several beams of light and monitor multiple pollutants. In contrast, sampling instruments are often designed to measure concentrations of just a single pollutant, resulting in rapidly increasing costs also if just a few types of gases are to be monitored in a few measurement points. In addition, a sampling system often requires more frequent maintenance and more consumables, compared to an open-path system. The latter might come with a somewhat higher initial price tag, but in the long run, the total cost of ownership is more favourable for open-path systems. The low maintenance requirements also make open-path systems less prone to handling errors, giving more uptime and reliable monitoring results.

In the end, the choice of instrument depends on what to monitor, and where to monitor it. A good supplier with good references will provide guidance to the best monitoring solution for the specific application.

Bengt Löfstedt is with Opsis

Godrej Process Equipment has shipped one of the World's tallest Continuous Catalytic Regeneration (CCR) Reactor to Dangote Oil Refinery, Nigeria. At 95 meters high, the CCR Reactor weighs approximately 703 metric tonnes, nine times heavier than a space shuttle.

CCR is the key process in oil refinery converting low value naptha to high valuable products like petrochemicals and gasoline through various reactions such as dehydrogenation, aromatisation, isomerisation, dealkylation, dehydrocyclization. The CCR Reactor is a tall column with a continuous moving catalyst. Very stringent tolerances are required to be maintained for installation of reactor internals. The equipment being in Hydrogen service, calls for a very critical metallurgy (Chromium Molybdenum Steel) leading to a very complex fabrication requirement.

Liberty pipe mills at Hartlepool, England has won a multi-million pound contract to supply steel pipeline for North Sea gas.

The mills, which were acquired and relaunched by Liberty, part of Sanjeev Gupta’s GFG Alliance, in late 2017, have just begun making the first batch of a total order for 12,000 tonnes of 24 inch steel pipe from global engineers Subsea7, that will be used in the Shell Shearwater gas field over 200 miles off the coast of Scotland.

Over the next few months workers at Hartlepool will make around 22 miles of heavy-duty pipe that will lie 90 metres under the sea, helping channel millions of cubic metres of gas each day to the huge St Fergus onshore terminal in Aberdeenshire.

This order, along with the Subsea7 contract to provide large diameter steel pipe for Equinor’s Snorre Expansion Project off the coast of Norway, is among the largest contracts secured by the Hartlepool mill since its acquisition by Liberty. It will ensure that both the 42 inch and 84 inch mills at Hartlepool have full order books as the operation moves into the Spring. 

Order books for both mills were also bolstered in recent months by major contracts totalling over 20,000 tonnes of pipe from the USA, one for the energy sector and another for the construction of chemical giant Lyondell Basell’s new showpiece plant in Texas.  

The comeback of the mills, which suffered badly during the downturn in the steel industry over recent years, has seen job numbers grow from 120 up to 200 over the past few months.

Angus 3D has produced its first pieces using a Markforged Metal-X metal printer.

 
The Metal-X uses Atomic Diffusion Additive Manufacturing (ADAM) technology – where metal powders are encased in plastic binders and then melted off to create designs previously impossible to manufacture and with unprecedented levels of detail as well as faster and at a fraction of the cost.
 
The Metal-X can also reduce the weight of traditional manufactured parts while maintaining their strength and performance by producing them with unique geometrics, such as closed-cell honeycomb infill. By printing metal powder in a plastic matrix, the it also eliminates the safety and environment risks associated with other 3D-printing methods.
 
Parts printed with the Metal-X are also up to 10 times less expensive than alternative metal-additive technologies and up to 100 times less than traditional fabrication technologies like machining or casting. Materials costs are typically reduced by up to 98%.
 
So far Angus 3D has used the Metal-X to print lightweight custom parts for a bicycle business and components for a new product design for an oil & gas company as well as remanufacture obsolete components for a local textile manufacturer to help maintain production and reduce breakdowns. It’s also producing test pieces for an F1 team looking for help carrying out performance analysis on parts.
  
Angus 3D’s Metal-X will further advance the circular economy by allowing parts which would previously have been scrapped due to obsolescence to be put back in service through reverse-engineering – where their design is replicated using a 3D scanner and then printed using the Metal-X. It also improves the benefit to the circular economy by using less resources in the process.
 
For example, an oil and gas company which had been scrapping electrical connections due to minor parts no longer being available is now having the parts reverse-engineered and remanufactured, allowing the connectors to be put back in service, saving nearly £20,000.
 
 

KLPE, an affiliate of United Chemical Company (UCC), initiated Kazakhstan’s first world-scale GSU project supplying feedstock to the polyethylene plant in Atyrau Region with a total capacity of 1,250 ktpa, which is executed in the framework on a joint development agreement between UCC and Borealis.

ILF Consulting Engineers (ILF) has been awarded with project management consultancy (PMC) services, including the supervision of the detailed feasibility study (DFS), to support KLPE, delivering this strategically important project.

“These strategic UCC initiatives pave the way in establishing the Republic of Kazakhstan as a global player on the polyolefin market. By using advanced technologies, engaging leading contractors and suppliers, as well as targeting for high levels of safety, reliability and operability, we aim to ensure the maximum return of capital investments,” says Maksim Sonin, UCC project portfolio managing director, member of the board.

“ILF is proud to support KLPE in this professionally led and fast progressing project. With the team’s ability of integrating ILF’s Western project management and Kazakh engineering requirements with local state-owned project execution processes, as well as permitting expertise, I am highly confident that the DFS phase will create the maximum value for UCC and its partner supporting their strategy of sustaining Kazakhstan’s development in the polyolefin market exploitation,” adds ILF project manager and area manager Upstream, Helge Hoeft.

The heart of the project is the NGL recovery facility, located close to the Tengiz oil field, with a maximum feed gas capacity of over 7 billion Sm3/a recovering ethane and heavier components as feedstock for the polyethylene project. In addition, a feed gas pipeline from TCO’s facilities, an approximately 180km long C2+ export pipeline to the polyethylene plant and a redelivery gas pipeline to GEEP pipeline, are within the project scope.

Presenting a recent case study, Chris Todd explains how three types of protection system for gas pipelines were deployed in the UAE

DUSUP (Dubai Supply Authority) recently specified a particular liquid epoxy coating for a buried gas pipeline project in Dubai, UAE. The project was undertaken by the main contractor Global Technologies Projects and Services (GTECH) with help from subcontractors Al Raha Metal Products Factory,  Al Raha Mechanical Equipment and WLL (Arm group of companies).

DUSUP required three solutions for three different types of infrastructure. Having already specified Denso Protal 7200 for the 24in diameter block valves and straight pipe lengths, it asked Denso to provide additional systems for the 2in diameter connecting valves and pipe tie-ins. Winn & Coales’ (Denso) lengthy experience in corrosion prevention enabled it to provide the following solutions.

System 1 (epoxy), for the 24in diameter block valves plus straight pipe sections.

The surface was abrasive blast cleaned to a clean near-white finish, SSC-SP 10/Nace No 2. An appropriate angular grit was used to achieve an anchor profile (63 to 127 micron). Chlorides were removed to an acceptable level of below 3 micro grams per cm2. A coat of Protal 7200 was then spray-applied over the entire area to a minimum of 508 microns and a maximum of 1,270 microns, in accordance with DUSUP’s specification.

System 2 (petrolatum), for the protection of the 2in diameter valves. After a thorough cleaning of the valve surface removing all dust, dirt and loose matter, a coating of Denso Paste was brush-applied over the entire area. This was followed by an application of Densyl Mastic to fill any voids and irregularities, creating a smooth surface for the following tape wrapping. Next, a spiral wrap of Densyl Petrolatum Tape with a 55% overlap was applied over the valve. A final spiral wrap of Denso PVC Outer Wrap with a 55% overlap completed the protection system.

System 3 (bitumen), for the protection of the pipe tie-ins. After the existing coating was profiled to a 20° angle, all dust and sand contaminates were removed. A brushed coat of Denso Primer D was then applied to the pipe area to be protected at a minimum of 150mm either side of the coating interface and allowed to dry. This was then followed by a spiral wrap by hand or pipe wrapping machine of Densopol 60HT Bitumen Tape with a 55% overlap. A final spiral wrap of the Denso PVC Outer Wrap was applied by hand or machine with a 55% overlap to complete the protective system.

Versotrac’s modularised components can be disassembled into smaller units, hand-carried into confined or remote spaces and then reassembled in minutes. No tools are required.

“This modular tractor system recognises the portability needs of ship, barge, offshore, wind tower and structural steel applications. Versotrac is a truly modular welding tractor, allowing users to take it anywhere without the need for cranes or other lifting devices,” said Magnus Svedlund, Global Product Manager SAW Equipment, ESAB.

The Versotrac can be rebuilt for optimum beam welding positions (including fillet welds in the flat position), comes in four- and three-wheel versions and can be adapted for both inverter-based AC/DC power sources and conventional DC and AC power sources. A new wire spool handling system detaches for easier transportation and more ergonomic loading of wire spools, while steering handles let operators easily change weld point position.

Quick-connect welding head

ESAB further enhanced the modular design of the Versotrac with its EWH 1000 welding head and EAC 10 controller, both of which detach. Their associated quick connectors and automatic detection/setup by the controller let users switch between the SAW, GMAW and Gouging processes in seconds.

The Versoarc EWH 1000 welding head incorporates a wire feed system that can weld with single wires up to 5mm and up to 1000A @ 100% duty cycle. For higher productivity (20+ kg/hr deposition), the Versoarc EWH 1000 can be used with twin wire process. A closed-loop encoder control system ensures precise wire feed speed control.        

It uses the entirely new and intuitive EAC 10 controller. Its simplified interface includes functions users need for tractor-based and other light-automation applications, making more room on the display for important functions like real-time, on-screen heat input to monitor and control weld quality. The EAC 10 pendant detaches from the base control unit so operators can work in a comfortable position and change settings from a distance. The controller works with all current ESAB submerged arc welding power sources, as well as most analog power sources on the market.

In the oil & gas industry, failing to perform ongoing maintenance on equipment can have severe consequences including reducing equipment service life, causing unplanned shutdowns and degrading performance, writes Denell Gibson. Ongoing maintenance is required to remove rust, corrosion and other accumulated material from the inside diameter (ID) of valves, pumps, piping, diesel engines, motors, natural gas compressors, flow meters and other large bore equipment. Often, this maintenance work is performed in the field under harsh conditions.  

Large diameter Flex-Hone tools are the ideal solution because they can be run with virtually any rotating spindle, are self-centring, self-aligning to the bore and self-compensating for wear.

The Flex-Hone tool is a resilient, flexible honing tool with a soft cutting action that provides a superior surface finish with a non-direction or crosshatched pattern. Whether it’s deburring a hole or blending an edge, removing corrosion or machining marks, using the tool results in increased product performance and longer product life. The Flex-Hone is designed for a variety of automotive, hydraulic, pneumatic and industrial applications in standard sizes as large as 36 inches.

TUV SUD NEL has just invested £1.45million in one of the world’s largest gravity test separators, as part of the build programme for its new Advanced Multiphase Facility (AMF).

 
The new separator will test both multiphase and wet gas flows (oil, water and gas) and will ensure sufficient retention time, even at the largest flow rates. Weighing 270 tonnes and operating at pressures up to 150 bar, it will enable flow rates within the AMF that are 20 times greater than the performance of any other test facility in the world. This will meet the oil & gas industry’s growing demand for flow meter testing that more accurately reflects real-field conditions, to reduce measurement uncertainty and minimise fiscal inaccuracy.
 
Infrastructure Manager, Muir Porter, is leading the installation project and said: “This is a major milestone for us as the test separator is at the heart of the AMF construction project. The next major phase will be to build the complex steel pipework which forms the test loop and feeds into the test separator, and which will deliver a multiphase flow test facility with a range beyond anything currently available on the market.”
 
The £16million AMF will focus predominantly on the £50-billion-per-annum global subsea sector and wet gas business. It will facilitate company-led industrial projects and product development, hands-on industry training and academic research. Creating at least 17 new jobs, the centre will futureproof the delivery of innovative technical services to the oil and gas production market for the next 25 years.
 
Scottish Enterprise has supported the development of the AMF with £4.9 million of research and development funding. Alongside the grant from Scottish Enterprise, TUV SUD NEL’s parent company, TÜV SÜD AG, is investing £11.1 million, which makes the project the largest capital investment to date in the company’s UK business.
 

Oilfield technology firm Airborne Oil & Gas and engineering company Símeros Technologies have signed an agreement which aims to deliver the first qualified Thermoplastic Composite Pipe (TCP) risers in the deepwater region Brazil.

 
Last year, Airborne Oil & Gas commenced its TCP riser qualification program. The technology is believed to be a world first for fully bonded, free hanging composite risers with the aim of providing a disruptive new riser pipe technology for operators with international deepwater applications.
 
The program is receiving funding from a major operator in the region and is aimed at qualifying the TCP riser for dynamic deepwater applications, including for pre-salt and highly corrosive conditions, against an ambitious timescale.
 
The TCP flowlines and risers developed by Airborne Oil & Gas can be installed by existing flex-lay and reel-lay vessels and be installed in the flexible and cost effective free hanging catenary mode. “Installed in free hanging catenary configuration, our TCP Riser provides the opportunity for significant savings on typical FPSO development, through faster installation and avoiding the need to use buoyancy modules”, said Oliver Kassam, Airborne Oil & Gas CEO.

Read about bearing requirements for risers here.

Greene Tweed has launched Arlon 3000 XT, a new thermoplastic for extreme conditions in oil and gas applications.

In dynamic mechanical analysis it demonstrated a glass transition temperature 35°F higher than PEEK, and provided superior mechanical property retention from 350°F to 600°F. In extrusion testing, it outperformed both virgin and filled grades of PEEK and PEKEKK.

Arlon 3000 XT provides improved volume resistivity 30 times that of PEK at 400°F and dielectric strength, measured at 730 V/mil using a 40 mm thick sample in ASTM D149 testing. In addition, it has 1.5 to 6 times higher mechanical properties compared to PEEK in tensile, compressive, flexural and shear tests at a test range of 392°F to 500°F, which provides the support typically provided by a metal element.

It is capable of withstanding all common oilfield chemistries, and is appropriate for use in back-up rings, v-rings, electrical connectors and seal assemblies.

BASF has announced the launch of Valor, its next generation Fluid Catalytic Cracking (FCC) catalyst technology designed to enhance the performance of FCC catalysts processing heavy residuum (resid) oil feedstock. Valor is BASF’s latest innovation in metals passivation. It leads to superior catalyst activity maintenance and enables refinery profit maximisation and increased sustainability of operations through higher and prolonged catalyst efficacy.

The ever-increasing number of refineries processing feedstock with high amounts of metal contaminants requires an FCC catalyst technology which effectively passivates these metal contaminants to mitigate their detrimental effect on unit operation. Valor addresses this important market need by effectively passivating Vanadium, thereby alleviating its destructive effects on FCC catalyst performance.

Refineries that used Valor technology in their FCC units achieved improved catalyst activity retention with lower hydrogen and coke yields.

Services division deliver successful projects to industry

The global services division of Oxifree Global has had a successful quarter delivering a number of projects within the Oil & Gas and Utility sectors.

Work has been underway with a large British utilities grid operator protecting current transformer and circuit breakers in the UK helping to ensure the continuity of electricity supplies in local communities. Recent projects have seen the protection of wellheads on storage caverns in Netherlands and France, one for a prominent chemical company and the other a national gas storage operator. In addition OGS have conducted offshore riser turret coatings on an unmanned OLT in the Netherlands with a large energy supplier.

With a number of large scale projects kicking off early next year, 2019 is shaping up to be extremely busy and a very exciting year for the new business.

Ed Hall, MD, says; “We have had a busy and exciting time for OGS and are pleased with the work we have done and the way we have been able to provide the ideal solutions for our customers. Our work on the OLT unmanned platform for instance, this was a great demonstration of how TM198 can provide a cost effective, no waste and speedy, space efficient solution to the problem. We were able to tick many boxes that are typically prohibitive to all services in this environment.”

The solution provided by OGS is Oxifree TM198, a thermoplastic coating for the protection of metallic components and complex structures.

Oxifree Global Services was formed to deliver a service operations and support subsidiary to the business in the UK.  The base in NE Scotland is run by Operations Manager Brian Smith housing personnel, equipment, stock, and training facilities in support of a quickly growing market here in the UK and Europe. In addition the team also offers support to our strategic partners local and abroad.

For further information, interviews, or visuals, please contact:
Laura Hall, Oxifree Marketing at laura.hall@oxifree.com

With asset utilisation critical and community and regulatory pressure always looming, it is essential that tank farm owners proactively prevent any loss of containment with reliable, cost effective corrosion protection. This is crucial since atmospheric corrosion is one of the main culprits of tank leaks, containment loss, and early replacement.

As oil depots and terminals are often comprised of ample pipeline through which to draw product, it is also vital to address corrosion under insulation (CUI), which can cause serious problems including forced shutdowns, lost production, etc. CUI, which involves the corrosion of vessels or pipe beneath insulation due to water penetration, is insidious because it can remain undetected until leaks occur or the insulation is removed for inspection. Consequently, dealing with CUI and inspecting for it are very costly.

Fortunately, by addressing a few important considerations regarding corrosion, tank farm owners can stop corrosion and CUI for years to dramatically extend tank and pipe service life.  In doing so, they can also improve safety, reduce downtime, and expedite maintenance turnaround.

Go beyond barrier coatings

Tank farm corrosion protection typically involves applying polymer paints and rubber-type coatings. Such methods create a physical barrier to keep corrosion promoters such as water and oxygen away from steel substrates. However, this only works until the paint is scratched, chipped, or breached and corrosion promoters enter the gap between the substrate and coating. When this occurs the coating can act like a greenhouse – trapping water, oxygen and other corrosion promoters – which allows the corrosion to spread.  

To extend the service life of tank farm assets, including those already experiencing atmospheric corrosion, owners and facility managers are turning to a new category of tough, Chemically Bonded Phosphate Ceramics (CBPCs) that can stop the corrosion, ease application and reduce production downtime even in very wet, humid conditions.

One example of this is EonCoat, a spray applied inorganic coating from the Raleigh, North Carolina-based company of the same name.  

In contrast to traditional polymer coatings that sit on top of the substrate, the EonCoat corrosion resistant CBPC coating bonds through a chemical reaction with the substrate. The surface of steel is passivated as an alloy layer is formed. This makes it impossible for corrosion promoters like oxygen and humidity to get behind the coating the way they can with ordinary paints.  

Although traditional polymer coatings mechanically bond to substrates that have been extensively prepared, if gouged, moisture and oxygen will migrate under the coating’s film from all sides of the gouge.  

By contrast, the same damage to the ceramic coated substrate will not spread corrosion because the carbon steel’s surface has been chemically transformed into an alloy of stable oxides. Once the steel’s surface is stable (the way noble metals like gold and silver are stable) it will no longer react with the environment and therefore cannot corrode.

Visible in scanning electron microscope photography, EonCoat does not leave a gap between the steel and the coating because the bond is chemical rather than mechanical. Since there is no gap, even if moisture was to get through to the steel due to a gouge, there is nowhere for the moisture to travel. This effectively stops atmospheric corrosion on carbon steel assets.

“CUI is the silent killer,” explained Merrick Alpert, President of EonCoat. “The insulation creates a terrarium on the steel in which corrosion is guaranteed to occur if traditional coatings are used. And the insulation then hides the corrosion from being detected until it’s too late.” 

Pipe is particularly susceptible to mechanical damage from shipping, installation, or facility operation that may breach traditional coatings and accelerate CUI.  

Because of the risk of CUI, a dedicated team is often required to inspect vessels or extensive piping on a virtually continuous basis. However, removing pipe insulation and spot-checking that portion of pipe does not eliminate the risk of CUI along the entire pipe network at the tank farm.

As an alternative that helps to curtail this costly inspection and maintenance cycle, a CBPC coating like EonCoat provides a corrosion barrier that is covered by a ceramic layer that further resists corrosion, water, impact, abrasion, chemicals, fire and high temperatures.

In this way, the ceramic layer provides a tough outer coating that dramatically reduces mechanical damage and any potential breach of the coating.  

The CBPC coating’s chemical bond further ensures that even if moisture were to get through to the steel due to a gouge, it would travel no farther than the boundaries of the gouge. This quality effectively prevents the hidden spread of corrosion, which is arguably the most insidious aspect of CUI.

One of the greatest benefits of the CBPC coating, however, is the rapid return to service that minimises facility downtime. The time saved on an anti-corrosion coating project with the ceramic coating comes from less surface preparation, the elimination of the intermediate coat and expedited curing time.  

With a typical corrosion coating, near white metal blast cleaning (NACE 2/SSPC-SP 10) is required to prepare the surface. But with the ceramic coating, only a NACE 3/SSPC-SP 6 commercial blast is typically necessary.

Furthermore, with traditional coatings, extensive surface preparation is required and done a little at a time to avoid surface oxidation, commonly known as ‘flash rust’, which then requires re-blasting.  

However, with the CBPC coating, the flash rust is no issue. The reason for this unique CBPC characteristic is due to the presence of iron in the rust, which helps to create the magnesium iron phosphate alloy layer.  It is this alloy layer that allows CBPCs to so effectively protect carbon steel from corrosion.

For traditional ‘three part system’ coatings utilising polyurethanes or epoxies, the cure time may also be days or weeks before the next coat can be applied, depending on the product.  

In contrast, a corrosion resistant coating for carbon steel utilising the ceramic coating in a single coat requires almost no curing time.  Return to service for tank farms can be achieved in as little as one hour, which can potentially save hundreds of thousands per day in reduced facility downtime.

For petrochemical tank farms with massive carbon steel structures, corrosion and CUI have been a costly, perennial problem.

Now, however, by proactively using anti-corrosion products like CBPC coatings, facility managers will be able to deter corrosion and CUI for decades, reduce downtime, and postpone tank and pipe replacement. 

Engineers from Severn Glocon Technologies have visited Korea to commission a High Integrity Pressure Protection System (HIPPS) supplied to shipbuilder DSME for a Floating Storage and Regasification Unit (FSRU).

 
The LNG FSRU vessel, BW Magna, has a capacity of 173,400 cubic metres. The HIPPS has been integrated and installed by Severn Glocon Technologies to protect the pipeline during the unloading of gas, enhancing safety for the FSRU and the downstream equipment and pipeline in the docking terminals it connects with.
 
HIPPS are not mandatory on FSRUs, but it’s increasingly recognised that they provide a superior level of safety and reliability. Situated between high-pressure upstream and low-pressure downstream units, they contain media if over-pressurisation is likely to occur, rather than venting. 
 
The system supplied to DSME operates at a working pressure of 117 barg. It comprises two 18” 900-class manual valves, a Sella Controls logic solver and three pressure transmitters.
 
Site Manager Tim Blake says HIPPS integration and installation requires a wide range of engineering and functional safety expertise. “Effective HIPPS integration demands electronic and mechanical engineering skills, with software engineering input sometimes needed as well,” he explained. “It’s important that these specialist engineers interrogate the design brief and collaborate with functional safety professionals. This is where using an independent integrator offers a major advantage. At Severn, we employ all of these professionals in-house.”
 
Additional safety measures on the FSRU include alarms, a shutdown system, blow down system and safety valves, as per industry-specified standards. The benefit of adding HIPPS is that it is a simple, proven solution which can operate independently of the wider vessel system.