It’s no secret that coatings last longer and perform better on a clean surface. Most cleaning methods, however, cause problems of their own. Dry blasting shatters the rust and coating on the surface and embeds abrasive contaminants to become stuck into the roughened surface. Wet abrasive blasting with untreated water causes flash rust. Other salt removers only remove a few salts, while replacing them with other salts and leaving behind an acidic, conductive residue. A new solution from a US-based company offers impressive cleaning without contaminants, flash rust, residue or film. It is naturally proving popular in the oil & gas sector – a market where durable, corrosion-resistant coatings are an absolute necessity.

HoldTight completely removes all salts and therefore all conductivity. It also removes abrasives and debris from the surface’s profile, providing a better surface area to bond with coating. Since it leaves a clean, rust-free surface for up to 72 hours, large areas of structures can be blasted and cleaned completely before coating application, instead of having to be coated immediately after blasting every day.

The product can be worked into any blasting process to achieve a totally clean surface, with zero flash-rust and zero residue left behind. It is a clear, simple additive with visible results, eliminating both natural and artificial contaminants. Throughout the oil & gas sector – from upstream to downstream – the solution is safe to use and compatible with a wide variety of surfaces, including steel, concrete, fibreglass, aluminium and composites.

Blasting water treated with HoldTight onto a surface prior to coating removes all naturally occurring contaminants (salts, acids, conductives). The solution also removes byproducts of the blasting process (shattered abrasives, dried paint) lodged within the pores of the surface, allowing for the most adhesive bond possible between the surface and the coating.

The cleanest surfaces are achieved when the product is used in both the blast and wash-down cycles at a 50-100 (water to HoldTight 102) ratio. The product extends the life and value of oil & gas assets for just pennies per application.

Operators can also save time and money with HT 365, a new thin-film coating that can be applied to blasted surfaces, preserving the blast and preventing flash rust and corrosion for up to one year. It can be applied to untreated surfaces or those that have been treated with HoldTight 102.

By preserving the blast for up to one year, HT 365 allows personnel to work with maximum efficiency, giving operators peace of mind that their surface is properly prepped for a quality coating – even if the project cannot be completed right away.

This new product is easily applied by brush, spray or dipping and easily removed by high-pressure washing with HoldTight 102-treated water.

Ken Rossy is with HoldTight. www.holdtight.com

To analyse the long term performance and reliability of hard working valves and pumps, serial innovators Manchester-based Bifold Group has adopted radio frequency based torque transducers from Sensor Technology Ltd for two of its specialist test rigs.

By using the power of computer aided design many of Bifold’s products are built to custom designs, yet they are produced to very short lead times thanks to the efficiency of internet communications. To maintain this standard, sample products and components are comprehensively tested so that their reliability and capabilities are never in doubt.
   
So when Bifold wanted to assess the effects of wear on its long-life valves they set about designing a special test rig. Engineer Andrew Laverick recalls: “We wanted to measure the power required to operate the valve to see how it changed over time and with long term use. It was clear that the best way to do this was to measure the torque input over an extended period.”

“We were open to any design concept for the test rig, but soon found ourselves gravitating towards a TorqSense solution because the Sensor Technology engineers were so helpful and really knowledgeable about test rigs.”

TorqSense transducers lend themselves to test rig uses because they are non-contact measuring devices. Attached to the surface of the transducer shaft are two Surface Acoustic Wave (SAW) devices, when torque is applied to the shaft the SAWs react to the applied strain and change their output. The SAW devices are interrogated wirlessly using an RF couple, which passes the SAW data to and from the electronics inside the body of the transducer.

Sensor Technology’s Mark Ingham explains: “All you have to do is set up a TorqSense transducer in the test rig and fire it up. The SAW frequencies reflected back are distorted in proportion to the twist in the test piece, which in turn is proportional to the level of torque. We have some clever electronics to analyse the returning wave and feed out torque values to a computer screen.

“TorqSense has been used on many test rigs over the years and I was delighted to hear the Bifold engineers say how easy it is to use and how robust the software is.”

Laverick again: “As a test engineer you are almost resigned to long set up procedures and software that falls over at the drop of a hat. But Sensor Technology has designed these problems out of their TorqSense equipment, with the result that we were able to complete our long term test procedures with the minimum amount of fuss and heartache and well within the allotted time schedule.”

In fact Bifold has since bought a second TorqSense which is being fitted to a new test rig used to assess the performance of mission critical chemical injection pumps, as used at oil and gas wellheads and on process pipelines.

“This project is proceeding well,” says Laverick, “and is allowing us to further develop our abilities to quickly provide bespoke equipment for ultra demanding applications, safe in the knowledge that it will perform faultlessly over a long working life.”

Peter Johnson explains why a big LNG project calls for an engineered solution

Globally, this particular LNG project is a very significant, large and technically complex, energy development. In essence, the project is ingenuity at its best. Innovative technologies have been used where possible to deliver this project and ensure that once in operation, it continues to run with little to no downtime.

Located about 220km offshore Western Australia, the field represents the largest discovery of hydrocarbon liquids in Australia in 40 years. This LNG project is currently in construction and is ranked among the most significant oil and gas projects in the world. It is effectively three mega-projects rolled into one, involving some of the largest offshore facilities in the industry, a state-of-the-art onshore processing facility and an 890km pipeline uniting them for an operational life of at least 40 years.

In operation, it is expected to produce at capacity up to approximately 8.9 million tonnes of LNG per annum and 1.6 million tonnes of LPG per annum, in addition to about 100,000 barrels of condensate per day at peak. A Final Investment Decision was reached in 2012 and first production is scheduled to commence towards the end of 2018/beginning of 2019.

Fabrication

The construction work for the offshore facilities was carried out at a shipyard with the responsible classification society. Offshore facilities consist of a CPF (Central Processing Facility) and an FPSO (Floating Production Storage Offloading). On the CPF there are several risers and riser guide tubes that will be placed around the facility. Due to the size of the columns, they need housings to ensure alignment. There have been concerns that movement of the columns against the housings will cause erosion-corrosion and impact. As the CPF has a design life of 40 years, it was decided to protect the columns and housings with composite bearings.

Composite bearings are generally installed around propulsion areas on ships. There are several ways to install bearings, however once they reach a certain size, the best option is bonding. Due to the size of the bearing required, in this case bonding was the only option to choose.

Belzona has vast experience bonding composite bearings, especially around rudder pintle areas on ships. After a trial ship application in 1979, the material was accepted as a permanent installation and used from new on all Germanisher Lloyd classed vessels. One of the first and perhaps most notable bearing bonding applications in service today was performed on a flagship liner, Queen Elizabeth 2. Bearing bonding is carried out by injecting the Belzona material between the bearing and the housing. The Belzona shim takes up any ovality or housing wear, thus creating a durable barrier with 100% surface contact, electrically isolating the bearing.

There are other adhesive products available on the market, however due to the 40-year design life, Belzona was chosen due to impressive testing, case histories. The company holds a certification for the products that are used in this process.

Bearings split into sections

The bearings were supplied in various sizes to match the columns and housings; some of the bearings reached 2.5m in diameter and 3m in length. As the sizes were so large, the bearings were split into sections. This meant that once the bearings were in place, the seams between each section would have to be dammed to stop the injected adhesive from leaking.

Belzona 1321 (Ceramic S-Metal) was used as the adhesive to inject between the housings/columns and the bearings. As Belzona 1321 does not cure based on a high exotherm, unlike chocking compounds, the gap could be reduced between bearing and substrate. This reduction of product quantity and application time ultimately saves on costs to all.
 
Due to the scale of this application, specialised techniques were created by Belzona Asia Pacific staff and the application team were trained up on life-sized equipment. One of the new techniques adopted was the use of a nylon jacking bolt which doubled up as an injection port for the Belzona 1321. This saved on the amount of holes that needed to be drilled into the composite bearing.

Belzona inspectors were present during the whole application in Geoje and ensured that the high standards were kept through use of QA/QC documentation.

This LNG project is now nearing completion, scheduled to go in production towards the end of 2018/ beginning of 2019. This project has truly been a testament to modern engineering and it will not be long before it commences its 40-year life, bringing much needed resources and infrastructure to the local and global community.

Low shear technology developed by Typhonix and used in the Typhoon Valve Systems is the Innovation Award Winner of this year at ONS2018 in Stavanger, Norway. Winning the Innovation Award is a recognition for Typhoon Valve System and confirms the prowess of Typhonix and Mokveld in low shear valve technology. Where Typhonix in Norway is developing the low shear technology and Mokveld Valves BV in The Netherlands is manufacturing the Typhoon Valve Systems.

By reducing shear forces in control valves and choke valves, Typhoon Valve System is a cost effective solution for cleaner production. It is the most cost-efficient solution to debottleneck separation and produced water treatment systems as it does not require any additional equipment, simply replace the existing valve.

In every process plant you will find sources of unwanted shear forces creating emulsification of oil and water. The main principle behind low shear processing is prevention of separation problems caused by droplet shearing of the production fluids in conventional valves. Replacing these existing valves to low shear versions gives significantly improved separation and less oil residues in the produced water.

In contrast to conventional choke and control valves, Typhoon Valve uses patented trim technology to involve a larger fluid volume that is actively dissipating energy. By using low shear valves and pumps it is also estimated that greenfield separation plants can be built 30-50% lighter and smaller, which will have large cost saving potential on both OPEX and CAPEX for the oil companies.

Typhoon Valve System enables users to reach higher well production rates, to extend late-life field production, to reduce the footprint of the process plant and of course to produce cleaner oil or produced water.

Knowing your inventory is an absolute necessity and how well you manage it directly affects your bottom line. Arguably, the materials that go into building any facility are the most important part of the whole project. This holds true for all parts of the oil and gas value chain - downstream, midstream, and upstream. There are a lot of moving parts to keep track of and your inventory is mobile, so why shouldn’t you be?

The 2018 MHI report states that while the current adoption rate of mobile technologies in supply chains is at 23 percent, it is expected to surge to 73 percent over the next five years. Mobile inventory management is growing, and to stay ahead of the competition, companies can’t get left behind by waiting to adopt mobile technologies.

Efficient inventory control means that inventory is not tied up when it is uncalled for. It means having 100% inventory visibility, and avoiding spending money on new materials without prior knowledge of what exactly is in your inventory. Inventory issues can arise if you don’t have current and real-time stock reports of everything that is currently in the yard. Mobile inventory applications create more inventory visibility that leads to reduction in redundant procurement, minimizes leakage and maximizes utilization.

Lack of knowledge of stock positions can hurt your bottom line. Having a warehouse management solution that can tell you what you have in stock at any time, and in real-time, can make a big difference in supply chain optimization. Once your business has a more efficient process in place, there is a positive effect on customer service, which is much needed at a time when customer service expectations are already at an all time high. Think of the innovative retail giant Amazon. Amazon will do everything in their power to remain customer focused, and they have the supply chain technology to back it up. Though, your warehouse is likely not ready to start testing with drones or augmented reality, there are lessons that can be learned from Amazon’s drive for achieving optimum supply chain management and the importance of customer satisfaction.

Concerns about lack of internet connectivity? No problem. Offline mode in mobile is available for operations in remote areas. Cloud based inventory management delivers a seamless solution for mobile and desktop. Using mobile devices improves the way you track what materials come in, what materials are shipped out, and what materials remain in the storage yard. All of this captured data is received through pre-configuration and barcode scanners on a mobile phone. This system tracks materials and empowers employees with linked access to detailed inventory records whenever they need it.

There are a handful of compliance and regulatory requirements that are of concern when you’re managing pipeline inventory. Regulatory requirements such as:

• Individual product specifications
• Material Test Records
• Reference documents
• Health, Safety, Environment, and Quality (HSEQ) requirements
• Technical requirements
• Transportation & Handling Requirements

Having your materials and inventory in check (on a mobile and desktop environment) leaves one less step to stress over. Accessible documentation is the key to compliance, and having a digital inventory management solution makes all of that paperless! Information about specs becomes easier to retrieve with warehouse inventory management software. Collaborate across your organization, and share data with ease. Not only can you enhance mobile capabilities but you can do even more by integrating with ERP systems.

The implementation of innovative technologies in supply chain increases transparency and encourages quick information sharing across the enterprise. If you would like a demo of Petro IT’s Stack61 to help with your material and inventory management (Stack61 is an Intelligent Warehouse Inventory Management Solution by Petro IT) please click here.

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.

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.

Constant monitoring of critical motors and generators on offshore oil platforms while offline prevents failures on start-up, reduces production interruptions, saves on rewinding repairs and increases personnel safety

For decades, offshore oil and gas personnel have performed insulation resistance tests with handheld megohmmeters to prevent motor and generator failures that lead to costly unplanned shutdowns, production interruptions and rewinding repairs. However, these tests only provide a snapshot of motor or generator health. In a matter of only a few days, windings and cables that are exposed to salt air, moisture, chemicals, contaminants or vibration can become compromised and fail at start-up.

The Challenges Of Megohmmeters

Portable megohmmeters also require electrical technicians to manually disconnect the equipment cables and connect the test leads on potentially energised or damaged equipment to perform the manual testing. These tests expose technicians to potential arc flashes when they access the cabinet. In the USA, non-fatal arc flash incidents occur approximately five to 10 times per day, with fatalities at the rate of approximately one per day.

With so much at risk, offshore platform operators are recognising the value of continuous megohm testing and monitoring of insulation resistance that initiates the moment the motor or generator is off and continues until it is re-started again.
 
Armed with this information, maintenance personnel can take corrective actions ahead of time to avoid a failure that would interrupt production. By doing so, they can save oil and gas producers hundreds of thousands of dollars in lost production and repair fees for expensive rewinding as well. Furthermore, permanently installed automatic testing devices allow for ‘hands-off’ monitoring without having to access cabinets – keeping technicians out of harm’s way.

How To Protect Motors On Offshore Platforms

Offshore platforms rely heavily on their main generators and a variety of motors, though the number and type vary depending on the size of the platform and rate of production. On a deepwater or ultra-deepwater platform, several hundred motors may be installed, with five-10 categorised as critical or significant (high-cost motors that are not easily replaced). On exceptionally large platforms, up to 30 critical motors might be involved.
 
These motors, which can range from 460V up to 13,200V, are found in crude oil export pumps, circulating water (saltwater, utility, fresh) pumps, fire pumps, cement pumps, gas compressors and fans. Medium-voltage generators in the main power plant, as well as low-voltage standby generators that back up the main generators and power lifesaving equipment are also critical to the operation of the platforms.

Unfortunately, this equipment is subjected to ice, moisture, changing temperatures and dense salt-fog. The salt-fog is one of the worst problems because the salt, combined with the moisture, can cause severe damage to the electrical insulation inside the critical motors and generators.

“The offshore environment is probably one of the harshest environments for electric motors and generators,” says Donna Lee Hodgson, senior electrical engineer for Shell International Exploration and Production. Hodgson currently designs deepwater facilities for projects in the Gulf of Mexico. “I have seen motors come into the shop that have salt encrusted on the interior of the stator windings,” says Hodgson.

Sand is also prevalent on deepwater platforms given the constant sandblasting and re-coating of carbon steel structures. “Basically, the sand that you are blasting at the carbon steel structures around the equipment tends to get into the motors and generators too,” explains Hodgson. The sand breaks down the insulation coatings on the windings, which leads to premature failures. The environment is so corrosive that Hodgson typically specifies enclosed or weather-protected motors.

Preventative Maintenance Programmes

In addition, most offshore oil operations engage in a time-based preventative maintenance (PM) programmes. As part of the programme, insulation resistance tests are typically scheduled on a semi-annual or annual basis. Typically, insulation resistance tests are also conducted at the start of annual overhauls or planned outages, to identify any motors that need repairs.  

According to Hodgson, critical motors on the deepwater platforms are tested to determine the equipment’s Polarisation Index (PI). The PI is used to determine the fitness of a motor or generator and is derived by calculating the insulation resistance of the windings using a portable megohmmeter.

The test begins with a reading of insulation resistance recorded at one minute, then a second test reading is taken for 10 minutes. The ratio of the two measurements provides the PI, which should be above 2.0.

Still, despite these types of tests, motors and generators can become compromised within only a few days in the corrosive, dirty environment and fail at start-up. When this occurs, costs quickly mount for “rewind” repairs or replacing the motor or generator while production comes to a halt. “Failures can be really expensive. Rewinds can cost tens of thousands of dollars, up to a couple hundred thousand depending on the type of motor or generator,” says Hodgson.
 
“And it is not just the cost of the repair,” she adds. “It is also the cost of the labour to get the motor or generator prepped and ready for shipment, the cost for the boat to bring it to and from the platform, and road transport. Those costs can also run in the tens of thousands of dollars.”

To avoid these costs, electrical engineers are turning to a continuous monitoring device, the Meg-Alert. Hodgson says she first heard about the automatic insulation resistance testing device through some of her colleagues.

What Is A Meg-Alert?

The Meg-Alert unit is permanently installed inside the high-voltage compartment of the MCC or switchgear and directly connects to the motor or generator windings. The unit senses when the motor or generator is offline and then performs a continuous dielectric test on the winding insulation until the equipment is re-started. By testing continuously, it reduces the need for manual PI testing since the insulation resistance readings are averaged over a longer period of time to determine the true ‘leakage current’ level of the insulation.

The unit functions by applying a non-destructive, current limited, DC test voltage to the phase windings and then safely measures any leakage current through the insulation back to ground.  The system uses DC voltage levels of 500, 1,000, 2,500 or 5,000V that meet the IEEE, ABS, ANSI/NETA and ASTM International standards for proper insulation resistance testing voltage based on the operating voltage of the equipment. The test does not cause any deterioration of the insulation and includes current limiting technology that protects personnel.

The Meg-Alert device can also be installed to disable the start circuit to prevent the motor or generator from being operated if the insulation resistance level is unsafe for operation. It is for this purpose that Hodgson installs the device on the generators on the deepwater platforms. “The Meg-Alert is wired to the start circuit so when you hit the ‘start button’ you get an automatic insulation resistance test and if it doesn’t stay above a certain setpoint, it will not start the generator,” explains Hodgson. “What that does is take human error out of the equation.  No one has to remember to use a megohmmeter before starting up the generator – the test is automatic and the equipment will not start if it’s not safe to use,” says Hodgson.

The Benefits Of Hands-Off Monitoring

The continuous monitoring system also allows for a hands-off approach that does not require service technicians to access control cabinets to perform a manual insulation resistance test. Instead, an analogue meter outside on the control cabinet door shows the insulation resistance megohm readings in real time. The meter also indicates good, fair and poor insulation levels through a simple “green, yellow, red” colour scheme. When predetermined insulation resistance set point levels are reached, indicator lights will turn on to signal an alarm condition and automatic notifications can be sent out to the monitoring network.

“With the Meg-Alert, personnel do not have to open junction boxes and connect a megohmmeter to the motor or generator. They can just look at the meter and alarm lights on the panel,” says Hodgson.

Continuous monitoring also indicates if the heaters used to maintain thermal temperatures and prevent condensation from forming on the stator coils and cables are working properly. If these heaters fail to operate properly or the circuit breaker is tripped, maintenance personnel may not be aware of it until the motor or generator fails on start-up. Although these heaters are checked regularly, this can leave critical motors and generators unprotected for weeks or even months.

How To Prevent Arc Flashes

According to Hodgson, safety is another major driver behind the decision to install the Meg-Alert devices. Arc flashes are an undesired electric discharge that travels through the air between conductors or from a conductor to a ground. The flash is immediate and can product temperatures four times that of the surface of the sun. The intense heat also causes a sudden expansion of air, which results in a blast wave that can throw workers across rooms and knock them off ladders. Arc flash injuries include third degree burns, blindness, hearing loss, nerve damage, and cardiac arrest and even death. Among the potential causes of an arc flash listed by NFPA 70E includes “improper use of test equipment.”

Although de-energising equipment before testing and wearing appropriate personal protective equipment (PPE) is recommended, the best solution is to eliminate the need to access the control cabinets at all to perform insulation resistance tests. “Two hazards we would be concerned about on a platform are electrocution and arc flash,” says Hodgson. “Given that generators on platforms are located within feet of the load, this is even more of a concern because of the high short circuit currents.”  

Welding is still the most widely recognised method for joining pipe systems together. However, there’s an additional connection technology that is worth considering: the High Performance Flange (HPF) system.  Ramiz Selimbasic details this time-saving and cost saving alternative to welding.

What Is The High Performance Flange (HPF) System?

The High Performance Flange (HPF) system is coordinated to common pipe sizes from 25 to 150mm diameter and wall thicknesses up to 20mm. It is designed for flange sizes ¾ to 5in hole patterns according to ISO 6162-1/2 (Code 61/62), ISO 6164. High-performance flanges are manufactured as finished machined and type approved according to International Association of Classification Societies (IACS). This therefore results in consistently high precision and quality during processing, so that these components no longer have to be reworked at the installation site.

The best solutions for complex design problems can often be found in nature. The flaring of a tube is similar to the shape of a branch where it joins the trunk of a tree. The tube is flared by hydraulic axial pressure giving it a parabolic shaping, increasing from 10° up to 37°. The initial gentle incline of the shaping guarantees additional safety against strong system vibrations.

The most essential part of the HPF connection is the locking flange design, which supports the pipe from the outside and provides additional protection against it tearing out of the connection. An insert is placed into this specially formed pipe. This insert seals on the connection side either via a special profile seal or an O-ring and on the pipe side via an O-ring. The insert has no toothed contour, which thereby makes repeated assembly work possible without any problems.

The Benefits Of The High Performance Flange (HPF) System?

This HPF principle results in a series of practical advantages as Hans de Lang, production manager at Royal IHC, confirms. In addition to ship construction, the company, which has been in existence since the 17th century, also manufactures pipe systems and accessories for the offshore market and has been using the HPF system.

“The system is universal for working pressures up to 420 bar and is therefore a versatile application method. As we provide solutions for the offshore and underwater markets, this aspect is very important for us. In contrast to conventional O-rings, the special profile seal is particularly resistant to gap extrusion,” says de Lang, thereby highlighting an aspect that is important for his area of responsibility.

“The HPF system is comparatively compact. This refers to the minimum length from the connection to the starting point of the pipe bend. Since we always implement designs that only permit little space and play, the HPF system is a very helpful product for us. Our fitters and assembly workers appreciate the fact that, unlike other mechanical flange systems, HPF inserts can be easily replaced if damaged during installation and pipe forming can be done on site. Also, bolts and screws can be easily tightened even under difficult conditions. All in all, high performance flanges have proved themselves to be tear-proof and vibration resistant. Safety plays a very important role for us,” says de Lang.

Returning to the welding technology mentioned earlier, this traditional technology is comparatively time-consuming, because heavy wall pipes connectors require several layers of welding and must be made by qualified welders. All welds have to have an X-ray inspection and the pipe systems must be flushed through. These intermediate steps can be omitted when using the HPF system, which is also more environmentally friendly. The flanging process does not cause noxious gases, thus eliminating explosion and fire hazards.

How Safe Is The High Performance Flange (HPF) System?

Parker’s HPF components are supplied as standard with a highly corrosion-resistant surface – an aspect that plays an important role across all industries. This surface finish is also free of CrVI, which is suspected of causing cancer.

“Parker always provides a comprehensive service package from design, production and on-site installation that the end customer can take advantage of. But this is not binding on what we can provide. For example, we can also execute pipe end forming ourselves on site with an assembly machine, which makes us even more flexible”, says de Lang. Explaining how the Parker Parflare HPF 120/170 functions, he says: “The machine is used for pipe end forming in the axial pressing process for the HPF flange system. It is a workshop device for single piece production. The flanging contour is achieved by axial pressing of the tool into the pipe end. The contour of the flange is designed for use with HPF inserts.”

The tool’s feed-in movement is generated by a hydraulic cylinder driven by a unit in the machine housing. The return stroke is also executed as electro-hydraulic. The pipes are clamped in clamping jaw sets that are clamped over a cone. The machine is equipped with an adjustable stop end for the pipe end. This therefore produces flange contours of uniform quality. The separated clamping jaws and the pipe stop end enable easy handling and uniform results. The separation of the clamping jaws and the removal of the pipes is facilitated by a bracket. Another practical feature of the Parflare HPF 120/170 is that it can be moved quickly to any location on rollers or by fork-lift truck or crane. In summary, the high-performance flanges can be assembled easily, quickly and, above all, safely.

Ramiz Selimbasic is with Parker

Learn how bearing vibration in an offshore 4MW thruster motor has been fixed through an  innovative joint effort.

Large marine thrusters are vital for the safe manoeuvring of vessels, but their location on board can make maintenance a considerable challenge. So, repairing a failed bearing and housing on an offshore accommodation vessel – as found in a recent case study –would require technical expertise as well as innovative and flexible repair procedures.

Working in the North Sea oil fields, the conditions can be far from favourable, so a safe and pleasant living environment is essential to all offshore workers. Accommodation vessels are co-located with drilling rigs to provide living and recreation facilities for the crew.

The semi-submersible accommodation vessel is designed to house up to 450 personnel. It uses a dynamic positioning system, DP3 in this case, as well as a 12-point mooring arrangement to hold position at sea. The thrusters are a vital part of the system and need to be maintained in perfect operational condition.

Replacing The Bearings

The primary maintenance contractor contacted Sulzer reporting high vibrations in one of the main thruster motors, which are located in the pontoons, after the OEM was unable to support the maintenance request at short notice. The project required the bearings to be inspected and replaced as necessary before recommissioning the thruster motor.

Since this type of repair had never been carried out on this vessel, it was essential that Sulzer carefully surveyed the motor and its location before creating a risk assessment and method statement in line with the vessel’s operational guidelines. The site survey also identified all the tooling and access equipment that would be required to complete the repairs.

The highly skilled site engineering team, based at Sulzer’s Aberdeen (Dyce) Service Centre, put together a detailed plan for completing the project, before flying to Kirkwall in Orkney. From here, the engineers travelled by boat to the vessel and boarded by boat-to-boat transfer.

Accessing The Motor

Once on board, it was apparent that access to the motor would be quite a challenge, with its location in a confined space and the close proximity of bulkheads. The project would require a well-planned procedure to achieve the bearing replacement.

The first task was to disconnect and remove the drive coupling, which was accomplished using the latest technology in induction heating. Jim McClean, Site Services Divisional Manager in Aberdeen, explains: “Heat is required to relieve the interference fit between the coupling and the motor driveshaft. In a workshop environment this would be achieved using gas torches, but due to safety concerns this equipment was prohibited.

“With so much of our work being offshore, we needed a quick and safe method of heating components, and this led us to use specialist induction heating equipment. The system we use has been developed specifically for use in offshore applications and it saves a significant amount of time during repairs such as this one.”

Due to the vertical orientation of the motor, the Sulzer engineers could only repair one end at a time to ensure the rotor was supported during the work. The non-drive end (NDE) bearing was replaced and all the surfaces were inspected and found to be in good condition.

The drive end (DE) bearing was inspected and found to be pitted, and the outer race had been rotating in the housing causing it to also be damaged. As a result, the affected parts were removed for repair.

The damaged housing was immediately shipped to Sulzer’s Falkirk Service Centre, where the machine shop applied metal spray to build up the damaged areas before machining it to the original OEM specifications – all within 24 hours. While the mechanical repairs were being completed, the site engineers on the vessel carried out the electrical tests that had been agreed with the vessel’s owners.

Once the repaired housing was back on board, the engineers rebuilt the motor and reconnected the driveshaft before recommissioning the thruster and taking vibration measurements to confirm the effectiveness of the repair.

McClean concludes: “Working in the offshore environment requires considerable expertise and qualifications as well as a liking of less conventional forms of transport. The customer was keen to repair the thruster motor as quickly as possible and that led to the conversation with Sulzer. With well-equipped facilities and the capacity to work around the clock, we have minimised any downtime and delivered a challenging project on time.”

Liam Jones details how electric actuators powered by solar panels improve shale gas well pressure stability in USA

The Haynesville/Bossier rock formation dates back to the Jurassic Period and covers large parts of South West Arkansas, North West Louisiana and East Texas in the USA. The formation contains large quantities of natural shale gas sourced from low permeability mudstones.

Why Does The Pressure Stability Need Improving?

Rotork’s customer required an actuation solution to carry out modulating duties on wellhead rotary non-rising choke valves in the East Texas section of the formation. The remote location of the wells meant a system that could operate effectively without a mains electricity supply was specified.

How Was The Pressure Stabilised?

Rotork IQTF electric actuators were installed and powered by a DC supply using a solar system and battery pack. This was considered a more reliable option than hydraulic or pneumatic actuation as it avoids potential leakage common in hydraulic actuators. Electric actuators also use less power than hydraulic alternatives while the long hours of sunlight can be used as a reliable solar power source.

The lightweight, compact IQTF actuator offers fast and accurate valve control and can perform up to 1,800 starts per hour. This was an important factor as a tight well threshold was needed to avoid over pressure in the main trunkline. If too much gas is extracted in a short period of time the reservoir can implode or cause ground fractures which water or gas can infiltrate and cause a loss in production.

Rotork Site Services carried out final commissioning while support was also provided during initial testing and calibration.

The Results

The actuators are controlling the flow and pressure of gas and condensate, a mixture of liquid hydrocarbons formed when pressure and temperature decrease as a result of well drilling, at the site near the city of Lufkin. Two IQTF actuators have been installed on each well to operate choke valves to step pressure down from 10,000 psi to 1,200 psi. The shale gas is metered between the wellhead and midstream trunkline where it is transported to domestic supply customers and industries including LNG plants and power stations. More than 30 are also being held in the customer’s inventory.

Since installation the flow rate at the wellheads has been within a tighter tolerance. This is important to maintain the stability of the well and flow as well as the pressure into the main trunklines.

The IQTF actuators combined with solar systems have proven so reliable that the customer is now using the solution at two of its other production sites, Shreveport in Louisiana and Eagle Ford in Texas.

The actuators are helping the customer produce 190,000 barrels of oil equivalent per day in Texas and Louisiana through activities at both the Haynesville and Eagle Ford basins, as well as the Permian-Delaware basin.

Liam Jones is with Rotork

Coriolis mass flowmeters are increasingly specified for entrained gas applications and although they have challenges, leading Coriolis manufacturers have developed technologies that enable their meters to work with two-phase flow. Frank Grunert explains more.

The oil and gas sector continues to face considerable challenges due to the falling and consistently low price of energy. Despite this, companies are expected to maintain high standards of quality and performance while improving efficiency. To meet these challenges, forward-looking firms are turning to cutting-edge technologies to stay competitive.

One proven way to improve efficiency is through accurate flow measurement – which is critical in upstream, midstream and downstream O&G processes. However, entrained gas in liquid (two-phase flow) has traditionally had a significant effect on measurement and performance in O&G applications and although systems are designed to prevent or remove entrained gas, this is not always successful or even practical.

What Are The Problems Of Two-Phase Flow?

Two-phase flow causes problems for most flow measurement technologies. Some are unable to measure at all when entrained gas is present, others will measure the gas as liquid – giving a measurement error proportional to the gas volume fraction (GVF), and others will stop measuring when the GVF reaches a certain level. Adding a further complication, changes in process conditions can cause the flow regime and GVF to shift, making it difficult to predict and manage.

The Challenges of Entrained Gas

Entrained gas presents a particular challenge for Coriolis flowmeters that calculate fluid density from the frequency of the measuring tube as the fluid passes through it. The lower the frequency of the tubes, the greater the density – and vice versa. During two-phase flow the gas and liquid ‘decouple’ and move at different speeds through the flow tubes, which dampens the tube vibration. Varying process conditions also cause the flow regime, GVF and tube frequency to change rapidly.

In the past, this rapid change in frequency caused Coriolis flowmeters to ‘lose’ the signal from the sensors mounted on the measuring tubes. As well as giving wildly erratic and non-repeatable measurement, the meters would often freeze at the last confirmed reading or go into reset mode having assumed that an internal error had occurred, resulting in no measurement of the process.

What Are The Solutions?

The leading Coriolis manufacturers have developed technologies that enable their meters to work with two-phase flow (albeit sometimes with limitations) but have come at the problem from very different angles.

Krohne first provided a two-phase flow solution in 2012, with the inclusion of Entrained Gas Management (EGM) as a standard feature on the MFC 400 transmitter that is fitted to all Optimass flowmeters.

Using high-speed digital signal processing and software-based algorithms, EGM makes constant and precise corrections to the tube driver level based on real-time frequency information received from the sensors and driver feedback. This allows the flowmeter to provide continuous and repeatable mass flow and density measurement across a wide range of gas volume fractions and complex flow conditions. Although Krohne does not specify an accuracy (in the company’s experience, the shifting nature of the flow regime and GVF make each application unique), it does point to the fact that EGM has been successfully proven in use for many years.

Frank Grunnert is with Krohne

In some oil pipelines, pressure reduction systems are installed to guarantee a smooth and safe operation (mainly in pipelines with high elevation differences). Such systems convert pressure or kinetic energy into heat. The question is whether it is also possible to transform the kinetic energy into electricity? The answer is yes, as Thomas Rother explains.

ILF recently had the chance to investigate a potential pipeline system for the installation of a turbine for energy recovery in a crude oil pipeline. The system needed to overcome a hill. To avoid slackline regions, which makes it easier for leak detection and pigging, a back pressure control valve (PCV) was installed. Depending on the pipeline system flow rates the PCV converted energy in the range of 1.5MW to 8MW.

Energy Recovery Configurations In Pipelines

Starting with two pipeline sections, the potential energy that could be recovered was discussed. One main aspect was that the energy recovery system must not influence the goal of the pipeline system: oil transport. Another aspect was that pipelines are normally operated at different throughputs with changing pressure conditions. The resulting system curves needed to be considered when selecting the recovery system, which could be a reverse-operating pump or turbine. In addition, the task of the recovery system influenced the sizing of the energy recovery system. Energy can be produced either for consumers in a demand-driven island-mode or for a grid with a maximum possible energy recovery mode.

In general, systems can be used where pressure reduction or back PCVs are installed. At each pressure reduction valve pressure will be converted into heat, vibration and noise. In the above example a 48in pipeline is considered. A hill (with about 700m height) is located 30km upstream of the storage tank terminal.

Within the project it was decided that only one unit, either one pump as turbine (PaT) or one turbine, should be used. Together with the required power recovery range of between

1.5 and 3.5MW, at all given process conditions (flow/pressure) the task was to find proper solutions for both systems. For a pump there is one characteristic curve. To recover a specific amount of energy the pump must be operated at the corresponding intersection point between the system curve and pump characteristic.

Fig. 1 shows the system curve (blue) together with the pump characteristic curve (red line). The green line shows the recovered energy that can be obtained (for a certain crude density of 834kg/m³). The energy values of the green line are calculated by the pump head, pump flow and efficiency. Pump characteristic curve and energy recovery curve cover always the same flow range.

The recovered amount of energy is given at the intersection point between the system curve and the pump characteristic. In this case the recovered energy would be about 3.6MW. The pipeline flow is about 5,000m³/h, the flow through the bypass PCV, PCV-D is 1,620m³/h and an additional pressure loss of 50m must be generated at PCV-C.

For turbines, the given ratio between flow and pressure head leads to a design with operating points on the left side of the turbine characteristic. The required energy can be recovered in the range between 1.5MW and 3.5MW. However, the turbine is oversized regarding the initial approach. The potential energy recovery of the turbine is up to about 8MW.

Using that turbine it was possible to recover the requested energy with all different pipeline operations. The request to recover energy up to 3.5MW even at smaller flow rates requires turbine operation with high differential head. This enables the turbine to recover energy up to 8MW, too. To handle the higher amount of energy, the electrical system needs to be adapted accordingly.

The Challenges Of Energy Recovery Systems

The installation of the system must be done in a way that the main goal of pipeline operation is possible all the time. Therefore, the energy recovery system needs to be installed in parallel to the existing line. In addition the existing task of the control valves must be kept. That is to control the backpressure – to avoid slackline operation.

The energy recovery systems can only be used if the pipeline is operation. Furthermore, the energy recovery system must be easily started and stopped.

In case of a pipeline emergency shutdown (ESD), the turbine generator will be stopped immediately; energy can’t be recovered any more. In this case the grid load must be considered. The evaluation of the grid stability is one of the main tasks. If the recovery system is designed for island mode, a kind of priority list can be installed to stop electrical consumers in preferred order. In island mode it is also important to ensure the energy balance between energy recovery and consumers. What happens if the island consumers need less energy than the minimum recoverable energy? In that case the installation of a load bank can help.

What Is The Benefit Of An Energy Recovery System?

It can be estimated using the following rule of thumb. Pressure loss (in bar) of the PCV divided by 10 and multiplied with the flow rate [m³/s] results in the potential energy (in MW). Assuming that 70% of the potential energy could be recovered this leads to:

P [MW] =  dP [bar] / 10 * Q [m³/s] * 0.7”

The energy recovery is only an add-on. It is not required for the normal operation and main task of the pipeline. One important question needs to be clarified: is it possible to feed the grid all the time? Together with the pipeline availability this results in the benefit of such systems. Assuming 10 €/MW, the earning per year (in total 70% of the year energy recovery operation: 6,132 h) can be calculated:

Earning [€] =  P [MW] * operating hours [h] * 10 [€]

Example 1 =  3.5 [MW] * 6132 [h] * 10 [€] ~ 214.000€ 

Example 2 =  2.1 [MW] * 6132 [h] * 10 [€] ~ 129.000€

Installing energy recovery systems in oil pipelines is not something that’s done as standard. There is no general, ready-to-use solution. Each system must be designed individually and the required machines must be carefully selected. Therefore, there must be close contact with the manufacturers. In contrast to many conventional tasks, such projects also have to take into account the efforts of the manufacturers, as otherwise it may be difficult to obtain the necessary information in time.

Thomas Rother is with ILF

When it comes to toxic fluid handling at offshore pump facilities, Thomas Neumann explains how robust pump technology minimises the risk of leakage when pumping condensate mixtures

In addition to contamination caused by sand and water deposits, crude oils and natural gases contain numerous non-marketable – and therefore unwanted – components such as hydrogen sulphide and chlorine. Breaking down these components and processing them further is not economically viable.

For this reason, the pumped fluid within a condensate application is purged of these by-products, which are then pumped by process diaphragm pumps into the gas flare of the offshore installation, where the toxic and unusable residual mixture is burned off, or passed onshore for disposal. To avoid endangering personnel and the environment during this process, the pump systems being used must be robust and leak-free. An intelligent material selection for avoiding sulphur-induced stress cracking or stress corrosion is just as important as having a pump with a low net positive suction head required (NPSHR).

According to the International Energy Agency (IEA), crude oil pumping is steadily increasing around the world. In 1990, just under 3.1 million metric tons of crude oil were removed from the ground, and in 2006 this figure rose to 4 million metric tons. Currently, the amount of crude oil being pumped is at an all-time high of more than 4.5 million metric tons – a trend that can also be seen in the natural gas industry, according to IEA.

In that industry, the amount of gas pumped quadrupled within just under 50 years, reaching a record amount of 3.6 million metric tons. The high demand on the raw material markets can be largely attributed to hydrocarbons, which are present as fossil fuels in products such as gasoline, diesel fuel, heating oil or biogas and which serve as a starting material in countless chemical synthesis processes. The crude oil and natural gas being pumped, however, contains both hydrocarbons and contaminants such as water and sand deposits, in addition to several non-usable substances. This includes substances such as chlorides and hydrogen sulphides. Further processing of these substances does not make economic sense.

How Are The Materials Separated?

While the flow is being split into crude oil, natural gas and water, the unwanted components are separated. The purified raw materials are transported by pipeline or ship for further processing, whereas the separated materials flow into a connected tank, since otherwise these separated materials would accumulate in the reactors, leaving less volume for splitting the raw materials. From this drum, the toxic mixture is forwarded by the use of suitable pump systems to the flare located on top of the installation, and is burnt there.

To ensure that hazards to personnel and the environment can be ruled out when pumping the separated products to the flare, it is essential that hermetically tight process diaphragm technology is used. However, pumps with conventional designs featuring dynamic seals, which are mostly made of low-alloy or highly non-corrosive ss316 steels, cannot meet these requirements, as they are not suitable for pumping hazardous mixtures.

In addition, the materials lack robustness, making them susceptible to the hydrogen sulphide corrosion and sulphide stress cracking that may occur upon pumping these fluid mixtures, which frequently contain H2S and chloride. In these applications, experienced pump manufacturers such as Lewa use duplex, super-duplex or nickel-based materials that are more resistant to corrosion and less susceptible to damage induced by sulphide and hydrogen sulphide. This way, leaks can be ruled-out over the long term, making more efficient continuous operation possible.

Optimising Suction Characteristics In Pumps

In addition to the right material selection, safe fluid handling also means using a pump with the right design. As a result, it is of paramount importance that there are no moving sealing surfaces between the fluid and the environment, since these have a minimum leakage determined by the system, even in the best-case scenario. The frequently used API674 pump design does not meet this requirement due to the fact that the plungers and packing are wetted and are thus not hermetically tight.

Although a packing design with a sealing system can catch or prevent any leaks that may occur, the frequent sand and particle contamination of the fluid shortens the lifetime of these dramatically, leading to not only additional installation, but also higher maintenance costs. The system must be maintained regularly and monitored using additional instruments to ensure proper functioning over long periods.

Pump designs by Lewa, on the other hand, are compliant with the API675 standard for ensuring process reliability when pumping combustible or toxic fluids as well as fluids that contain solid materials or have high viscosities. These pumps do not have dynamic seals with relative movements between the seal and the sealing surface. This rules out fluid leakage caused by the system.

An additional advantage can be found in the M9 pump head with a reinforced suction stroke thanks to the spring-actuated diaphragm return movement. Thanks to this design, the Lewa M9 pump heads have suction characteristics unlike those of other pumps. These pump heads can operate without cavitation, even at low net positive suction head (NPSH) values. This property is absolutely vital when pumping condensate, because the tanks are usually positioned at the same level as the pump and the fluids have a lower steam pressure. Without the optimised suction characteristics of the M9 pump heads, the tank set-up or the tank itself must be modified to raise the net positive suction head (NPSH) value, which would be very costly.

How To Analyse The System

To coordinate the pump and the facility’s piping system to each other, it is useful to calculate how the piping responds to the pulsing excitation of the pump. Taking into account the system complexity, the number of pump cylinders and the fluid properties, these types of pulsation analyses can provide recommendations for orifices and other attachments that may be necessary depending on the circumstances. For the discharge side piping sizes of pulsation dampers/resonators are calculated, if other measures are not feasible.

These analyses also incorporate the ways in which the pump system behaves and responds while multiple pumps are being used simultaneously, with safety valve response pressure and at varying speeds. Lewa has used its in-house test-bench to verify these calculation programs through real-world trials. The company’s expertise in this area means that the requirements for optimal component dimensioning and positioning are met before the planning phase is over, ensuring that the pump system functions as desired and runs smoothly. It also means that subsequent modifications will not be necessary.

Summary

In applications where hydrocarbons are pumped as a component of crude oil and natural gas, the pumped fluid is separated into different components before it even leaves the offshore pump facility. This prevents unnecessary transport of non-marketable materials from the main pump flow. These unwanted contaminants, including both chlorides and hydrogen sulphides, are separated using a condensate application and directed into the flare of the offshore installation or passed onshore for disposal.

It is essential that this be done using pumps featuring hermetically tight process diaphragm technology. This is because the systems being used have to operate without leaks to guarantee maximum safety in handling toxic mixtures. At the same time, a low net positive suction head required (NPSHR) is advantageous when using the unit, since this means the pump can be integrated into the facility without costly changes to the facility.

The process diaphragm pumps produced by Lewa are capable of providing this added value. This also applies to the pulsation analyses developed in-house, which use numerous simulations to ensure optimal dimensioning and positioning of the components and thus help to improve the reliability and durability of the overall system.

Thomas Neumann is with Lewa

An application in media delivery can often be handled by using different pump types. However, optimum results and material-preserving transport require exact matching of the pump to the different parameters such as viscosity, temperature, NPSH value or shear sensitivity. Netzsch Pumps & Systems has therefore widened its portfolio of progressing cavity pumps and rotary lobe pumps by three model series of compact screw pumps: the Notos untimed twin, three and timed twin screw pumps.

Depending on the type, they are suitable for lubricating and non-lubricating products to be transferred at high pressures up to 80 bar and temperatures up to 350°C. They thereby cover a wide range of application areas – from lubricants to sealants and on to bitumen or resins – and thanks to their compact design they fit into limited spaces, as they are found often on vessels, offshore platforms or other production facilities.

Thanks to special materials, hydraulic compensation and geometry optimised through FEM simulations, all Notos pumps are designed for highest efficiencies and long operating life.

The core feature of the screw pumps from Netzsch is their High Efficiency Unique Design (HEUD), delivering a high power-performance ratio. In 2018 the IBExU Institute for Sicherheitstechnik confirmed that Notos multi screw pumps meet the requirements of explosion groups IIB and IIC (and therefore also explosion groups IIA, IIB and IIA) for ATEX certification. In addition, suitability for use in explosive atmospheres at ambient temperatures between -20° and +40° was confirmed.

AUMA actuators for multiport valves in hydrocarbon service support up to 16 ports with a combination of high speed and excellent precision, thanks to their variable speed motors. Positioning accuracy is better than 0.3° and lift plug valves are also supported, making the actuators suitable for the most challenging applications in this market.

Multiport valves require high positioning accuracy as they direct fluids from many different production inlets in turn to a single sampling system. AUMA’s SAVEx variable speed actuators achieve this through precise slow motion as the valve plug approaches its target port, virtually eliminating overrun. For most of the valve travel the motor runs at full speed, so cycle times remain short.

The SAVEx multi-turn actuators are rated for open-close duty and positioning duty (classes A and B) / (short-time duty S2-15 min). Special sizing for longer running times is available for the S2-30 min duty. Meanwhile, SARVEx multi-turn actuators are rated for modulating duty (class C) S4 - 25 %. Special versions for S4 - 50 % are also available.

Multiport valves featuring a lift plug design make actuation even more demanding because two different movements have to be coordinated: before the plug can rotate to the desired port it first has to be lifted from its seat. AUMA’s clever solution is to use two actuators in a master-slave configuration that appears to the DCS as a single actuator. The integral actuator controls handle the complete sequence of movements and the safety interlock that allows rotation to start only once the plug has been lifted into its ‘free’ position.

Tube Tech International has announced that its multi-million-dollar Shell Side Jet innovation has begun live demonstrations to the open market. The innovation, which is the result of a multi-million-dollar R&D investment, guarantees to remove fouling from the outside heat transfer surface of shell and tube exchangers for the first time.

Developed by Tube Tech International, with R&D funding from the Horizon 2020 programme, via the SME Instrument, Shell Side Jet has been created to meet the demands of the petrochemical market for a solution that can clean in-between shell side tubes. Its makers believe it will be the only technology able to tackle shell side fouling with guaranteed results.

Derek Sumsion, R&D Manager for Tube Tech International, says: “The live demonstrations of our Shell Side Jet solution is a huge milestone for us, prior to the system’s launch in March 2020. We have spent years researching and developing solutions to the industry’s most difficult fouling challenges, and we are proud to be demonstrating this unique service, which we believe is the first of its kind.  

“The technology includes a detection system that is able to indicate bent tubes and severely fouled areas, protecting the asset and ensuring a more precise clean. We are also able to offer the client detailed digital reports that include information such as the distance of baffle plates, location of damaged or broken tubes, volume of fouling, photos of before, during and after the clean, and an intuitive heat map.

“Using this system, we can restore assets to near design thermal efficiency, in turn reducing CO2 emissions and improving productivity, which will ultimately save millions of dollars a year for refineries across the world.”

According to the German Energy Agency (dena), biomethane production in Germany may increase as much as 10 times over – from currently 9 terawatt hours to about 100 – by 2050. What is more, natural gas is the most important energy source for private households and accounts for 44% of the heating market.

Before natural gas or biogas is fed into commercial supply networks, it must have an odorant added to it. Odorants serve as a warning in case of leakage.

Since the last few years have been marked by a trend toward decentralised production, Lewa has added the MAH 4 size to its micro-metering pump portfolio as a proactive measure for meeting the expected increase in demand. The new unit can be used for odorising with mercaptans or tetrahydrothiophene at a throughput rate of up to 12,500Nm³/h. The pump covers the flow range from 200 to 250ml and can be used as a cost-effective solution in accordance with DIN-EN 1333 for gas networks up to PM 16.

“Back in early 2018, we started getting more requests for odorising gas volumes of approximately 12,500Nm³/h, to the point where it just made sense to design a pump specifically for that amount,” says Walter Richter at Lewa. “The right way for us to respond to this trend was to add an intermediate size, the MAH 4, to our hydraulically actuated and solenoid-driven micro-metering pumps from the MAH, MBH and MLM series. The new size meets the requirements for this range exactly.”

The new unit closes the gap between the MAH 3 and the MAH 5 – something that had previously been done using the larger MLM 15 series. However, the stronger stroke solenoid made that design over-dimensioned and less cost-efficient in some cases. Neither the MAH 3 nor the MAH 5 units from the same series were cut out for the job. There was always one of two problems: either they could not manage to pump at the required output of 16 bar, or they could manage a sufficient flow rate at 600ml but were not designed for the necessary discharge pressure.

To enhance efficiencies for asset owners in the oil & gas storage tank segment in the EMEAI region, Sherwin-Williams Protective & Marine Coatings has launched its new epoxy coating offering mildew-resistant corrosion protection with a long-lasting, more aesthetic finish.

The high-solids, high-build, fast-drying polyamide Macropoxy 646MR primer builds on the existing proven Macropoxy 646 technology, offering high chemical and abrasion resistance inside as well as outside of the tank with the added formulation of outstanding mildew resistance.

The new Sherwin-Williams solution keeps tanks and pipelines working more efficiently with a more aesthetic finish than previously available. With low volatile organic compounds (VOCs), application can be performed on site or in shop by brush, roller or airless spray.

“This coating is simple to apply without having to completely remove existing systems, and resists the growth of mildew on the exterior of tanks or external pipelines,” says Michael Harrison from Sherwin-Williams Protective & Marine Coatings.

Designed for use in maintenance, repair or in new construction, Macropoxy 646MR is an ideal durable corrosion protection coating for storage tanks, fixed roofs, floating roofs, vessels and pipelines.

The range of protective lining products offered by Sherwin-Williams is tailormade to each specification, combining exceptional anti-corrosive performance with effective chemical resistance.