Fronius has expanded its portfolio of manual power sources with three new devices for Tungsten Inert Gas welding (TIG). The MagicWave 230i, 190 and TransTig 230i are extremely practical, powerful and quiet. Thanks to their rapid signal processors, they always achieve the exact current curve that allows for maximum arc stability with the lowest possible noise emissions. With its intuitive menu navigation, users are able to access the correct parameters in just a few steps and can then concentrate fully on achieving a clean weld seam.

The most powerful power source is the MagicWave 230i for AC welding. It can communicate with other devices via Bluetooth, WLAN and NFC technology, and can be networked with them. The MagicWave 190 is ideal for welding materials such as steel, stainless steel or aluminium. The AC power source features gas cooling and is the best choice for a wide range of uses.

An integral part of the new line is the TransTig 230i for DC welding. Weighing 15.9 kilograms, it is especially light. This manual power source is suitable for all welding applications apart from aluminium. As with the MagicWave 230i, the power source can also be supplied with an optional water-cooling system. Using Bluetooth, WLAN and NFC, the TransTig 230i can also connect wirelessly to devices such as an intelligent welding helmet, remote control or even a smartphone.

The multilingual operating concept of the manual power source with a 4.3-inch full-colour display allows for intuitive and extremely simple operation. Using the favourites button, welders can easily retrieve and set parameters that they often use. The modular design is a particular advantage: users can expand these devices as desired with different function packages. These include the job function, which can store up to 999 jobs at the same time, the PulsPro package to obtain all pulse functionalities, additional data documentation and limit monitoring. The
latter aids the user in setting a defined parameter window and keeping to certain welding parameters. USB ports allow software updates to be
installed and welding data to be documented.

Every device is available as a multivoltage version. Using the Fronius Power Plug - a lockable plug connector on the rear of the power source -
the mains cable or plug can be changed quickly and easily depending on where the device is being used. This means it can be used anywhere in the world - even with different mains voltages. Fronius has also redesigned the welding torch: an ergonomic grip combined with a torch changing
system as standard increases comfort and convenience, and allows for even more precise handling. The integrated, high-performance LED illuminates the seam area efficiently, leaving the welder to concentrate entirely on their task and achieve excellent results.

InterMoor has completed work for the installation of the new Floating Storage and Offloading (FSO) facility Benchamas 2.

 
Previously, the Benchamas Explorer FSO, owned and operated by Chevron, was installed in 1999 in Block B8/32 in the Gulf of Thailand. The FSO began initial production in 1999 and after operating the facility for almost 20 years, Chevron decided to replace the aging facility with the new FSO Benchamas 2.
 
The new floating facility was delivered by MISC Berhad, and was converted from an Aframax-sized crude oil tanker. The project marked MISC's maiden foray into Thailand's oil & gas market.
 
InterMoor’s scope for the project included project management, engineering and manpower for the tow of the FSO Benchamas 2 from MMHE shipyard in Malaysia to the Benchamas field, offshore Thailand. InterMoor also chartered two anchor handling tug supply (AHTS) Vessels for station keeping during the hook-up of the FSO and provided engineering and analysis to support the hook-up of the FSO and installation of the riser system. The new FSO is turret-moored at the same location and connected to the existing mooring system and piles, in 71m water depth.
 
The work was completed on time, without interruption of production, and without any lost time incidents.

Oxifree Global unveil new Polymelt 50 applicator for use with TM198

In today’s challenging environments there is one constant and that is change. Modern organisations need to find a better way to do things with the commitment to improvement starting at the top. There is no doubt that looking at things from a new perspective brings about great change and that’s just what Oxifree have been doing with their new and improved Polymelt 50 machine.

Providers of anti-corrosion and contamination solutions, Oxifree Metal Protection offers TM198 – a thermoplastic coating for the protection of metal assets. Application of TM198 is fast and simple by their range of applicator machines of which the Polymelt 50 is a real workhorse.

“As part of our commitment to continuous product development, the PM50 has undergone quite the transformation to bring new benefits to our customers”, says Ed Hall, Managing Director. “The Polymelt 50 is our larger machine for the application of Oxifree TM198.  It has a tank capacity of 22kg/50lbs and comes with a 15m/50ft hose”.

To create the new machine Oxifree took feedback from their own projects, feedback from customers, reviewed the environments the machines operate in and looked at the demands in the market.
The new PM50 highlights include a 45% reduction in overall size making it easier to transport and manoeuvre on work site, a new contemporary design, soft wheels for improved impact/shock resistance and new machine usage and pump usage hour meters to aid maintenance planning. New machines began shipping at the start of the year and feedback so far has been very positive.

Oxifree TM198 is an innovative thermoplastic coating proven to increase the lifetime of metal components by as much as 1000%, and provide significant savings to the cost of maintenance.
Oxifree coating can be applied to live equipment without the need for costly shut downs. It provides protection immediately as it cools and solidifies within seconds on impact, even in the most extreme of environments.

Thierry Couturier explains why handheld X-ray fluorescence (XRF) analysers are a fast way to ensure safe operations

In the oil and gas, as well as chemical and power generation industries, preventing leaks and spillages via component failure is of vital importance. A reliable and comprehensive positive material identification (PMI) programme is an essential element to ensuring safe plant operation. Handheld X-ray fluorescence (XRF) analysers are well suited for fast, easy PMI measurements, providing a cost-effective way to prevent component failures and maintain plant safety.

The key to running a successful PMI programme is taking into account the specific challenges of the industry. In the oil and gas industry, harsh conditions – and the resulting risks of damage – are one of the most important challenges for inspection equipment. Furthermore, due to the scale of a typical plant, traceability and short measurement times – without compromising on reliability – are also critical for success.

Instantaneous grade and composition identification

In the oil and gas sector, pipes, solder, welds, connectors and screws all have to be made of the correct alloy for their application. Due to high temperatures and pressures, mechanical stresses and corrosive substances, use of the wrong type of alloy in one component can jeopardise the safety of an entire pipeline or vessel. In a comprehensive PMI programme, all these components are tested before operation and as
part of in-service inspections – or on an ad hoc basis, for example, in case of a missing certificate.

With the use of XRF technology this type of alloy identification can be carried out in seconds. XRF spectra reveal the relative abundances of metals, which are then automatically checked against a preloaded library of alloys and grades. This approach enables fast decision-making and saves time on PMI inspections.
The sensitivity of XRF analysers also makes the technology well suited for detecting trace elements. This feature enables XRF analysers to be used in other applications, such as corrosion inspection. For example, the presence of trace elements such as Cr, Ni, Cu in carbon steel can indicate RE corrosion in hydrofluoric (HF) alkylation units, or carbon steel with low Si content can exhibit significant accelerated/non-uniform corrosion due to the known sulfidation corrosion process.

Traceability and reliable report generation

A key challenge in the inspection of large plants and structures, such as long pipelines, is traceability of measurements. Even when measurement results are generated quickly, collating the data into detailed reports can make PMI inspections laborious and time-consuming. The large number of measurements involved also increases the risk of human errors in report generation.

To simplify the creation of inspection reports and improve measurement traceability, advanced XRF analysers are equipped with GPS, WiFi, Bluetooth and cloud storage. The combination of GPS and timestamping of all measurements saves time on reporting and reduces the risk of errors; easy internet access enables automated data sharing and archiving.

Dealing with the elements

The working conditions in industrial plants are often tough for inspection equipment. Damage due to water, dust, drops or shocks is highly likely when unsuitable equipment is used. Also, due to the layout of a plant it is often necessary to inspect in hard-to-access locations, for example using ladders.

Designed for portability and damage resistance, XRF analysers are well equipped to handle the harsh conditions of oil and gas plants. The devices are lightweight and can be carried in one hand or stored in a holster and worn on a belt. Additional features, such IP ratings, drop-tested design, detector shutter protection and cooling fans make
XRF analysers highly suitable for in-service testing.

Olympus’ Vanta XRF analysers fulfil all the requirements for a reliable efficient PMI programme in oil and gas plants. Vanta’s drop-tested, rugged design and IP65 rating improve return on investment by vastly reducing the risk of damage. These features, combined with fast results that are both accurate and repeatable underline its suitability for PMI programmes that help to avoid part failures and ensure plant safety
and profitability.

Thierry Couturier is with Olympus

Paul Hennessey discusses how ultraviolet disinfection is emerging as a best available technique for SRB reduction

As seawater and more recently, produced water re-injection is used to enhance oil production (enhanced oil recovery (EOR)), the need to control microbiological activity is high on the agenda for operators worldwide. In particular, sulphate reducing bacteria (SRB) that consume dissolved sulphates in the sea water and produce hydrogen sulphide (H2S) is of major concern due to the associated risks of microbial induced corrosion (MIC), well souring, reservoir plugging with iron sulphide (FeS) and damage to process equipment and infrastructure.  

Found naturally, SRBs are present in seawater used for well injection, but are typically only activated when introduced to anaerobic conditions such as a piping network or oil reservoir. Process stages such as vacuum de-aeration can lead to problems increasing or occurring earlier than expected. In addition to H2S formation, bacteria can proliferate and excrete extracellular polysaccharides that stick the cells together to form adherent slimes or biofilms, damaging equipment and causing blockages of porous rock strata, reducing yield and defeating the object of injection.

Traditionally the approach was to inject high doses of chemical biocides, e.g. hypochlorite or glutaraldehyde, at both continuous dosing and batch dosing intervals – ‘shock dosing’ – to kill SRBs and other bacteria present in injection water. In particular, SRBs can multiply at an alarming rate – given the right conditions they will double in number every 20 minutes. With over 220 strains of SRB, this reproductive cycle and natural genetic variation that occurs has led to SRB species becoming naturally immune to certain biocides. Changing to an alternative biocide provides a temporary solution in this war of attrition, until the bacteria become resistant and an alternative biocide is required.

In addition to the above, rising costs, changes in regulations such as OSPAR and HOCNF, and operational concerns with the delivery, storage and handling of chemicals has seen operators look to alternative disinfection solutions.  

Use widely in drinking water and wastewater, the chemical-free, physical treatment process of UV disinfection has emerged as a new ‘best available technique’ for injection water and, following successful pilot trials, is now being used to treat both seawater and produced water for re-injection in EOR applications worldwide.  

UV radiation in the UV-C band has a wavelength of 254nm, which is very close to the absorbance wavelength of the amino acid bases that form the ‘rungs’ of the DNA double helix. UV radiation fuses adjacent amino acid groups, making it impossible for the molecule to replicate and permanently damages the thymine strand of the DNA helix. Bacteria exposed to UV radiation then die at their next natural reproductive cycle.  

A major benefit is that unlike chemical biocides, no microorganism has shown any immunity to UV-C light. The UV intensity (or ‘fluence rate’) produced per unit area by a UV lamp is normally measured in mW/cm2. Multiplying this by the hydraulic retention time in the UV reaction chamber in seconds gives the effective UV dose (or ‘fluence’) in mJ/cm2. In particular, SRBs have proved to be very sensitive to UV-C, with standard UV doses used for drinking water disinfection of 20-40mJ/cm2 providing a >4 log reduction (99.99%) reduction of SRBs in a single pass (0.5 seconds exposure to UV-C light).  
 
As a chemical-free, physical process UV provides a range of process benefits and operational advantages. As regulations such as HOCNF become more stringent, operators have made the holistic link between injection water and returning produced water and its impact on environmental impact factors (EIF). Because UV does not introduce any residual compounds into the water, challenges regarding residual toxic chemicals in returning produced water or the formation of disinfection by-products such as halogenated hydrocarbons (due to the chlorination of seawater) can be reduced or in some cases eliminated – driving down operational costs whilst improving environmental performance.

Operationally, UV disinfection can reduce the need to ship, store and handle chemicals offshore, helping to improve safety and drive down operational costs.  In recent research (2016) conducted by Shell, the typical payback for using UV versus biocides for small flow application, e.g. 300m3/hr, could be as little as one to two years (onshore EOR injection well, the Netherlands).  

For larger flow rates >2000m3/hr OPEX costs can be significant. Another major oil & gas operator compared the costs of supply, transportation, handling, storage and injection of acrolein into 300,00 bwpd against those of a chemical-free, UV disinfection package. Based on a five-year operation calculation the biocide would cost £3,500,000 against only £130,000 in lamps, maintenance and power for UV.

UV disinfection plants are typically skid-mounted or containerised and when compared to alternative disinfection technologies such as electro-chlorination, are typically 50% smaller in footprint and weight. Models such as the WF or Wafer by atg UV Technology use modern ‘in-line’ designs that see UV reactor designs mimic butterfly valves, allowing for installation or retrofits into the tightest of pipe galleries.

Developments in power supply technology and UV lamp design have significantly increased both UV system capacity and operational life, with certain UV designs being able to operate continuously for over two years before requiring maintenance, making UV systems suited to future developments such as unmanned platforms and subsea installations.

In addition to seawater injection for well injection and EOR applications, UV disinfection is now being adopted for pipeline hydrotest water, produced water reinjection and more
recently, for the treatment of flowback water before reinjection in hydraulic fracturing (shale gas and oil) applications.

Andy Filkins reveals why innovation is the key to improved valve instrumentation

In the oil and gas industries cost management is a priority. This is driving more innovative solutions that reduce operational costs and/or optimise output. A telling example is the use of solenoids as the final element in the control circuit for pneumatic
on/off valves.

For emergency shutdown valves, partial stroke testing (PST) and sometimes full stroke testing (FST) is required to ensure the valve (system) works according to the site’s safety standards. A PST is a critical procedure as end users do not want a failure to cause a shutdown of their operations. Therefore, the actuator needs to be moved with precision over a controlled percentage of the valve stroke. There are various ways in which PST can be performed: mechanical, electronic, electric and pneumatic. With the PICO control system Rotork has devised a complete solution, integrating ultra-fast, zero bleed solenoid valves, high flow capacity filter boosters and a dedicated electronic control. This solution enables the performance of PSTs on the fastest valves on the market without endangering continuity of production and without the compromises or risks of conventional systems.

The high flow capacity filter booster integral to the PICO system is a new solution, which incorporates the combined functions of a filter regulator and a volume booster. The patented design allows up to 500% higher flow than other market equivalents, whilst eliminating the need for an additional poppet or quick exhaust valve in applications where a fast shutdown is required. Basically, the filter booster simplifies the circuit and reduces overall costs. Combined in a total circuit, the modular design creates a greater flow capacity through an unrestricted common bore system which allows for considerable cost savings compared to a traditional tube and fitting alternative.

Modulating control

Another major part of business for Rotork Instruments comes from process control applications where valve positioners are used to control the position of a modulating valve and to enable a fast response to the position of the valve from a command from the control system. Traditional systems use PID controllers and electric to pneumatic (I/P) converters. In these designs outlet air pressure from the I/P converter is regulated in proportion to an analogue electrical input signal and the highly accurate output pressure is maintained by an internal feedback sensor. Electro-pneumatic positioners incorporate the functions of the I/P converter, PID controller and the pneumatic module into a single unit, making the system compact and reducing pneumatic connections between multiple components, thus reducing possible leak paths.

Valve diagnostics

Besides the traditional solutions, Rotork Instruments is also active in microprocessor-based digital valve positioners with internal logic capability. In basic terms, SMART digital positioners perform the same principle function as electro-pneumatic positioners, combined with automatic calibration and configuration, delivering considerable time savings, improved process control and reduced process variability. Another bonus is the ability to diagnose in-line valve performance via the distributed control system (DCS), PC software tools or handheld communicators. There are also cost reductions in loop commissioning, including installation and calibration, and the use of diagnostics to maintain loop performance levels.

AUMA has supplied a turnkey valve automation solution to Indonesian national oil and gas company Pertamina. 12 SAEx multi-turn electric actuators with ACExC integral controls plus a SIMA control system support the first phase of an expansion project at the TBBM Manggis LPG tank farm, Bali.

AUMA’s SIMA control system is integrated into the tank farm’s existing SCADA system. It uses standardised Modbus RTU communication between the valve actuators and the higher-level SCADA system. The actuators connect to the SIMA in a ring topology with integrated redundancy. At SCADA level, the AUMA system with its Modbus RTU communications operates in parallel to an existing system with older actuators using a proprietary communications protocol.

“This project shows that a stepwise upgrade to AUMA in existing plants is possible at any time and without any problems,” says Stefan Kolbe, sales director Southeast Asia at AUMA. “The customer particularly appreciates the flexibility and future-proofness of the investment thanks to the open fieldbus standards. They also see benefits in the short response times of the AUMA solution, which allow optimised process control.”

AUMA supplied a complete turnkey package to Pertamina, including installation and commissioning of the actuators and hassle-free integration into the SCADA system

For more information visit Auma

Netzsch Pumpen & Systeme offers in its product range not only the progressing cavity pumps but also the rotary lobe pumps and the three model series of compact multi screw pumps: the NOTOS two, three and four-spindle pumps. Depending on the type, they are suitable for non-lubricating substances at high pressures up to 80 bar and temperatures up to 300°C.

The core feature of the screw pumps is their concept following the high-efficiency unique design (HEUD) and producing a proven improved force-performance ratio. This is due, on the one hand, to the very hard materials used – the choice ranges from simple grey cast iron to chrome-nickel steel and on to duplex or Hastelloy alloys – depending on the requirement. The stability of these materials ensures very minor sagging of the spindles, even under the high loads typical for screw pumps; this allows working with very narrow tolerances between dynamic and static parts in the manufacturing process. Possible back-flow from the higher pressure to the lower pressure side is thus reduced and the delivery efficiency increased at the same time.

The shape of the spindles has also been adapted to minimise interferences and resistances in the material flow. Netzsch used sophisticated calculation methods in this process, e.g. the finite element method (FEM), permitting a realistic simulation of the pump and the pumping process with freely configurable parameters. In this way, the spindle geometry for the desired delivery characteristics could be determined and medium transport largely free from turbulence and pulsation achieved.

Beyond this, the choice of materials and the design ensure high robustness and service life of the screw pumps. In addition, each pump from Netzsch is designed specifically for the respective application area, especially in terms of size. This exact matching of technology and equipment to the application allows adapting to the specific properties of the medium and also the loads – due to the type of deployment – early on and to largely compensate for influencing factors that could lead to increased wear or damage.

For more information visit Netzsch

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.

Wanja Galewsky & Ramiz Selimbasic discuss a flexible piping system that offers operators an alternative to in-house solutions

Go it alone or get help from outside? This question arises very early when processing complex on- and offshore projects. It makes a lot of sense to look more closely at the service portfolios of potential suppliers.

Part by part comparison of price and performance is essential for making choices later. But the question also arises of whether the products under consideration are compatible with each other. On this point Parker offers a comprehensive product range, from the soft sealing EO-2 and O-Lok connections through to the F37 Parflange and high performance flange systems (HPF), with which most design jobs can be resolved.

Every built-in component receives its own identity through the Parker Tracking System (PTS) so that spare part procurement, in cases of repair or maintenance, is significantly speeded up and simplified.

Whilst the assembly of standard fittings may be straightforward, end users processing large-bored tubes up to 273mm are often not in possession of the required machinery. Here the Parker Complete Piping Solution (CPS) system is a useful alternative. This concept offers users freedom of choice to use (according to their needs) a meaningful proportion of this modularly designed system, from the design and engineering of the tube and flange system, through to their manufacture and installation at the assembly point.

The system has several service centres worldwide in which tubes up to an outside diameter of 273mm and, depending on requirements, bending radius of 2xD to 3xD, can be produced (cold bending) on the most up-to-date CNC bending machines.

Parker onsite containers are an interesting solution for manufacturing on site. They contain all the assembly machines that are needed for tubes from 6mm to 60mm diameter and, on request, up to 273mm. All the fittings and connectors available from Parker can be processed on these high-precision machines. This bending, cutting and cleaning machinery is supplemented by an equipment package that is essential for installation on site. From a business point of view on-site containers can be purchased or rented.

In the preparation and assembly of complex tube and flange systems, cleanliness is the highest priority after safety. Residues in a system can have fatal results. Parker hot oil flushing units are an additional service for cleaning tubing systems before they are connected to the main consumer. They increase the safety of the complete system and contribute to a reduction of maintenance costs. The flushing medium is mineral hydraulic oil, which is pumped through the lines with a flow rate of 3,000 l/min at a pressure of 75 bar (adjustable). The flushing units can also be used for pressure testing up to 630 bar and have a tank capacity of 6,000 litres. When the work is completed, the cleanness of the tubing system is documented by a Parker service technician on site.

Processing and assembly by “piping partners” offers a further alternative. The user has the advantage that they will be helped with procurement, processing and assembly anywhere on the planet by this close network of piping partners. These suppliers are certified by Parker so that the customer has the assurance that a competent and reliable supplier is standing alongside.

This service segment is rounded off by the Parker Maritime Service offering. At first glance they are very scientific - but in practice, exciting - tasks with which the team supports its customers. Measurements under the surface, sub-sea metrology, are carried out with the help of photogrammetry. The experts create photos and precision mapping images with special cameras, that enable the spatial location of the three-dimensional form of an object to be determined. This technology is used amongst others for the salvaging of wrecks.

For on-board technology, complementing the global GNSS navigation satellite system, Parker offers a special 3D reference system with which ships can at all times be held exactly on course. The coordinates system of this technology is based on the centre-line of the ship, the rudder-post and the reference plane arranged on the main deck. The experts are also on site when it is a question of precise mapping of the sea bottom. This procedure is an important prerequisite when choosing locations for wind turbines (monopiles) and connection components, including their installation.

The PMS position monitoring system is an important tool. For the offshore loading of oil this technology supports safe, trouble-free media transportation from ship to ship.
All in all, with its many worldwide service centres, components precisely matched to each other and systems from a single supplier, and with its experience in developing tailored, customer-specific solutions, the Parker service programme constitutes an attractive alternative to in-house solutions.

Wanja Galewsky & Ramiz Selimbasic are with Paker Hannifin

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.

Optimising industrial real estate is a key consideration when specifying critical equipment, particularly in the oil & gas and chemical processing industries. SPX Flow has introduced the CombiProLine OH3 vertical pump for applications that demand a small footprint without compromising performance.

The CombiProLine OH3 offers a space saving of up to 70% when compared to the equivalent OH2 horizontal pump. By eliminating the need for a baseplate, the CombiProLine is easier to install than horizontal pumps and offers a weight advantage that makes it particularly attractive for platform installations.

CombiProLine OH3 pumps can be used to move thin, clean or slightly polluted liquids as well as non-viscous and light viscous liquids at up to 300mm² per second. Typical examples include offshore installations and crude oil extraction, petroleum refining and distribution, processing of hydrocarbons (such as butane and acetylene) and gas processing, including methane, butane, LNG and LPG. Its unique combination of space-saving and performance parameters also offer benefits in water treatment and general industrial liquids handling applications.

Part of SPX Flow’s Johnson Pump Combipro family of heavy duty centrifugal pumps, the OH3 meets the requirements of API 610 and ISO 13709.

CombiPro pumps feature a number of design elements to prolong their working life and make maintenance simpler. For example, a robust, metal-to-metal fit between the pump cover and casing is assured using a special gasket to ensure proper sealing and alignment. An oil-lubricated bearing arrangement ensures smooth operation, with the option of cooling the oil bath in high temperature applications.

Disassembly and assembly of the bearing section and the complete rotor set can be undertaken without the need to remove either the motor or pump and without disconnecting the pipes, minimising downtime. A further benefit is the standardisation of parts, which offers high interchangeability across the Combipro range and greatly reduces spare parts holding for SPX Flow customers. It also means there are fewer variants to remember, making maintenance crew training much simpler.

Standard specification CombiProLine OH3 pumps are available for quick delivery. Customised models to accommodate lower or higher temperature variants, or other application-specific parameters, can be made on request but are subject to longer lead-in times.

ABB has been awarded an integrated automation, electrification and telecommunication order valued at US$79 million for the upgrade of the Bab Onshore Field in Abu Dhabi, by China Petroleum Engineering and Construction Corporation (CPECC).  

Spanning 1,200 square kilometers, Bab is the largest onshore oil field in Abu Dhabi. State-owned Abu Dhabi National Oil Company (ADNOC) has identified the potential to increase output from 420,000 to 450,000 barrels of oil per day (bpd) at the field by 2020. In 2015, ADNOC Onshore awarded the engineering, procurement and construction (EPC) contract to CPECC to upgrade the field.  

The upgrade will include a fully integrated ABB Electrical, Control and Telecommunication (ECT) solution with 45 power and capacitor bank skids, as well as centralised and localised automation systems. ABB Ability digital oilfield technology will further enhance the ECT solution to remotely monitor and analyse field performance where multiple oil wells will be co-located in one place. Once installed, it is expected to reduce the oilfield’s operating expenditures by 10 to 15%.

Peter Terwiesch, President, ABB’s Industrial Automation division said: “We are very proud to have won the contract on the basis of our ability to provide a fully integrated solution that leverages our process control system. In addition, we demonstrated the strongest local footprint, with our equipment being built or assembled in the UAE and our services delivered by locally-based staff.”  

The level of In Country Value (ICV) offered when tendering for industrial projects in the UAE has become increasingly important over recent years since the UAE Government announced its policy to enhance the role of private sector in appointing and training nationals.  

Terwiesch added, “Hiring and training Emiratis to become high-performing employees has been a focus for us in the United Arab Emirates in recent years. I am very pleased that our efforts were recognised by the UAE government in October 2018, when we received an UAE Emiratisation Award.”  

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

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.

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.
 
 

Heat, contamination and unpredictable weather constantly threaten to disrupt the performance of offshore oil and gas facilities. These unforgiving conditions can be detrimental to the performance of drilling equipment, pumps and extraction machinery — but what steps can be taken to ensure quality engineering at sea? Chris Johnson, managing director of SMB Bearings, explains why, sometimes, it’s the little things that count.

 
Considering the unpredictable nature of offshore environments, the first step to reducing maintenance requirements is to ensure the right equipment is selected in the first place — and this is imperative for both large-scale machinery and small components.  
 
Selecting the right parts

Generally, large-scale machinery found on offshore rigs, such as marine riser tension systems and cranes, are specifically engineered for use in these environments. Having been designed by a specialist marine engineer and manufactured by a marine-focused original equipment manufacturer (OEM), this machinery will be built with the unpredictable offshore environment in mind.
 
Smaller components however, are often purchased from suppliers that may not specialise in marine engineering — or understand how these environments would interact with certain components or materials.
 
Consider bearings as an example. Many bearing distributors supply a magnitude of bearings to a wide range of industries. For marine environments, stainless steel bearings immediately spring to mind but which grade of stainless steel? While the material is well known for its corrosion resistant properties, it does not necessarily mean it is ideal for offshore oil and gas applications. 
 
For example 440 grade stainless steel is known for its resistance to damp environments. Bearings made of this material are regularly used in environments subject to washdown and exposed to water, such as food and beverage manufacturing. Despite this, 440 stainless steel actually has very poor resistance to salt water.
 
In salt water or salt spray environments, 316 stainless steel bearings are a better option. In fact, these are commonly recognised as marine grade bearings. Despite this, they should only be used in marine applications above the water line, or in flowing, oxygenated water. Full ceramic bearings made from zirconia or silicon nitride can provide even higher levels of corrosion resistance and are often used fully submerged.
 
Ensuring quality and compliance

Material is not the only factor to consider when choosing a bearing for use on an offshore oil or gas facility. Customers should also enquire about other technical capabilities, such as the load rating and tolerances of a bearing to ensure it can withstand the environment in which it must operate.
 
When checking this, it is also worth investigating whether the bearings used comply with other standards, such as those related to quality control. ISO 9001 and ISO14001 are noteworthy standards to look out for. Naturally, it is not essential to choose the most expensive bearing on the market but selecting a high-quality bearing could save on repair and maintenance costs in the future.
 
Minimising maintenance

When selecting a bearing, customers should ask for the predicted lifespan of the bearing. In addition, are the bearing materials and lubrication suitable for a marine environment? Can the bearing run unlubricated with an acceptable lifespan as in the case of full-ceramic bearings? These are important considerations when specifying bearings that will run continuously with little or no maintenance.
 
That said, the lubrication requirements will depend on the specific application of the bearing, its load and the conditions in which it will operate.
 
Some bearing lubricants, for example, are not very water resistant and may eventually be washed out of the bearing in a wet environment hence the increasing use of full-ceramic bearings in marine environments.
 
The unforgiving conditions of offshore oil and gas rigs can wreak havoc on the machinery used on these sites. However, there are ways to ensure that, even the smallest of components, can assist and not hinder the smooth running of these difficult facilities.

Digitalisation refers to the use of technologies to convert information and data into a digital format in order to improve business processes, writes Stephen Webb from Metegrity. 

For owner-operators of pipelines, the single largest benefit of this process is the newfound ability to gain actionable intelligence from their data, straight from the right of way. Of course, that ability is contingent upon finding a technology solution that can deliver it. 

The problem

Operators could be missing out on significant profit potential if they are too reliant on outdated methods for collecting and analysing their documents and data. This includes data issued during all stages of pre-construction, such as front-end engineering design, materials procurement, welding specifications, land permitting, route crossing, etc. – in addition to the construction and inspection records generated during the pipeline construction. 

In fact, The Pipeline and Hazardous Material Safety Administration (PHMSA), has identified “material, weld and construction quality as a major source of leaks during pre-commissioning hydrostatic pressure tests, the first years of operations and later in life of a pipeline. PHMSA’s findings indicate a need for better quality assurance in the pipeline construction industry.”(1) 

Utilising paper-based processes such as spreadsheets and physical reports that are slowly filtered up the chain of command, operators aren’t able to receive pertinent information in a timely manner, or to gain any actionable intelligence from the data they do receive. When data is allocated from a variety of disparate sources in an inconsistent format, it becomes difficult to properly assess and analyse project data or asset health. In this climate, inspectors wait until the end of their shifts to fill out their physical reports (or else leave the work face, which comes with its own inherent risks), and then hand those off to be filtered up to the decision makers. This directly impedes project efficiency and opens the door for quality issues, as key information from the job is not immediately known. This increases the likelihood of lost profitability, safety or quality issues, and even asset failure. 

The solution

In an effort to reduce the risk brought on by construction quality, PHMSA created guidelines for a pipeline construction quality management system (QMS), as detailed in API 1177 – Recommended Practice for Steel Pipeline Construction Quality Management Systems. 

The key to solving these issues lies in modernising the entire pipeline construction process via digitalisation, utilising technology and software compatible with API 1177. 

Rather than waste time tracking down data from an array of multiple contractors, owner-operators are leveraging software platforms that can allocate all data – across all of the pipeline construction disciplines and stages – into one secure, robust database. Project information can be instantly uploaded in real-time to the database straight from the right of way. 

Field personnel can access key data right at the job site, enabling immediate decision making for construction-related issues. 

Inspectors can update the database with their findings as they go. Key decision makers can access and analyse the data to garner real, actionable intelligence in real-time, empowering them to make and pass down decisions immediately, and to implement preventative measures to prevent asset failure before it occurs. 

With immediate access to information, identifying incidents for regulatory compliance becomes automatic. For example, if a pipeline were to leak, operators can go back through the data and easily access all of the steps that were taken, who was working on it, and when, and then generate a report for regulatory bodies.

By removing the need to gather data from files or paper-based record systems, owner-operators can substantially reduce overhead hours. Predictive capabilities are greatly improved when key information about project status and asset health is immediately known and readily accessible. As the data continues to build within the database, a clear audit trail is formed and with the right technology, any variation of report or trending can be generated with the click of a button. Once the pipeline is in operation, this data can be utilised for ongoing pipeline integrity management during the asset’s operational lifecycle. In the future, this opens the door to machine learning and, eventually, to artificial intelligence. 

Ultimately, digitalisation equates to the ability to instantly gain and access actionable intelligence from pipeline construction data – which helps to improve understanding, drastically reduce response times, enable preventative measures where required, and ultimately reduce catastrophic instances during the pipeline’s inception through to its operations.

How to leverage digitalisation

With so many different forms of data across so many disciplines in the pipeline construction process, owner-operators might assume that the digitalisation process would be costly and daunting. Previously, that might have been the case. Not anymore. In the past few years, exponential leaps have been taken in technological innovation in this sector. With an abundance of digital technology available, and experienced consultants ready to perform the heavy lifting, the process of modernising construction projects is more affordable than ever.

The first step will be to allocate, consolidate and convert existing data from its current disarray of resources onto a single, robust database. To facilitate this, look for a company that provides professional consulting services. They will send in experts to assess the company’s current status, filter through current data, and digitalise all key information into the platform.

From there, the goal will be to implement a comprehensive pipeline enterprise system designed to align business processes with the work being performed in the field. The right system will align and connect data from the right of way to the office in real-time, allowing operators to constantly be aware of the project and garner actionable intelligence from their data. Automating the pipeline construction data with the right tool helps your organisation transition to a simpler, low cost business model. With all project data stored and built up on one database, this also provides the future benefit of helping companies save time researching project issues after the pipeline in the ground. For companies that are trying to move toward AI and machine learning, it is crucial to implement an enterprise software capable of advanced data analytics right from the pipeline’s inception. This will serve as the foundation for AI later on.

Look for a product that facilitates near real-time data capture straight from the right of way onto secure cloud servers for maximised efficiency and security. You should be able to access all information as soon as you sync your device, and then be able to push all project, engineering, material and welding specification revisions out to the inspector. The product should allow for reliability, accountability, and traceability – and it should support management review, management of change, and document and records control.

Consider the most advanced technology platforms to help maximise your investments. Look for innovative technology that delivers advanced analytics. This is what will enable you to run business intelligence on the collected data.

By aligning with a service provider that offers these technologies, you can quickly and affordably modernise your pipeline construction and digitalise all processes. As more-owner operators adopt this approach, it will become increasingly prudent to do so just to remain competitive – never mind the proven return on investment that has already been realised by companies who have taken the leap. The ROI will be realised right at construction, and then even more so over the continued operational lifecycle of the asset. 

Reference:

(1) Niesen, V. and Gould, M. (2017, November). Detecting Pipeline Leaks. ASME Mechanical Engineering, 139 (11), p 35-39