Uncategorised (70)

Wednesday, 12 March 2014 09:02

Technologies to Watch: March 2014

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Adaptor turns wired field instruments into wireless devices
Yokogawa has developed a multi-protocol wireless adaptor that enables wired field instruments or analytical sensors to be used as ISA100 Wireless devices, and will release models in May and July that support communications based on the HART and RS485 Modbus standards.  (Read more)

Magnet picks up profit from demolitiom waste
In the materials sector, Atlas Copco has introduced an interesting addition to its range of hydraulic tools for recycling plants, scrapyards and the demolition industry. Hydro Magnets enable valuable iron and steel to be separated quickly and easily from concrete waste for subsequent recycling. Installed on the existing grapple or shear installation, they require no extra generator or electro cable on the carrier.  (Read more)

Energy-saver demo highlights huge opportunity for UK industry
Huge amounts of energy are still being wasted throughout British industry because variable speed inverter drives are still not fully appreciated, so Mitsubishi Electric has developed a simple but effective demonstration that can be seen in an on-line video, operated as a virtual demo or used in reality at the company’s headquarters in Hatfield.
(Read more)

High-pressure pumping systems for steel industry
The steel industry encompasses a large number of very different processes, from the smelting of the raw materials to the rolling and shaping of the finished product. In the modern economic climate, it is essential that the equipment used in these processes is as reliable and efficient as possible.  (Read more)

CASE STUDY - Control valve threatened Welsh Water supply
Dŵr Cymru Welsh Water investigations of ‘pin holes’ by non-destructive testing of a strategic flow control valve found that in less than five years, cavitation had caused extensive detrimental and potentially fatal wear to the plug valve, which was in danger of imminent failure.  (Read more)
Wednesday, 12 March 2014 08:36

Appointment News - Enquest

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EnQuest PLC has appointed Neil McCulloch as president, North Sea, with effect from 1 April. He will succeed David Heslop, who retires from his role as managing director UKCS

McCulloch has held a number of senior positions in the oil and gas sector, and joins EnQuest from international oil and gas company OMV AG, where he had the global role of senior vice president production & engineering.

Prior to this, he spent 11 years with BG Group in a range of senior UK and international roles, most recently as vice president & asset general manager, UK Upstream, with accountability for the delivery of BG’s UK North Sea business.

Heslop is to continue to support EnQuest in an advisory capacity or on special projects.

EnQuest is currently investing £4bn in the one of the largest new oil fields in the North Sea, which could employ up to 20,000 in the construction phase and create 1000 operational jobs over its expected 25-year lifetime.

The 140m-barrel Kraken development will be EnQuest’s sixth production hub in the UK North Sea.

As operator, EnQuest will develop the project - located in the East Shetland basin, about 125km east of the Shetland Islands - on behalf of itself and its partners.

Around 80% of the investment will be in the UK, said the company, which estimates that the project will generate future revenue of £9 billion. Gross peak oil production is expected to exceed 50k barrels of oil per day, with first oil production in 2016/2017.

The Kraken development has two separate heavy oil fields, both of which will benefit from UK government tax measures to stimulate investment in the UK North Sea, said EnQuest, which claims to be the largest independent North Sea producer.

Energy technology services company Proserv has unveiled what it claims is a game-changing technology for subsea control and monitoring communications.

The Artemis 2G (A2G) subsea electronics module is a controls and communications tool. It is designed to free operators from the constraints of an existing brownfield umbilical by finding additional signal capacity to enable a cost-effective field upgrade or extension.

In addition, the design is said to offer high-speed, copper-based, multi-drop networks as a viable alternative to fibre optic infrastructures within the subsea production system.

According to Proserv, A2G provides more powerful communications and instrument support and increases accessibility for remote usage though its webpage interface from subsea to the desktop.

The product, it adds, complies with the latest ISO 13628 part 6, API 17F and Subsea Instrumentation Interface Standardisation. A2G can be used to co-exist with existing networks, is fully back compatible with all existing technology and does not require any proprietary software for remote configuration and support.

With the extraction of subsea oil and gas reserves becoming increasingly challenging in deeper and more isolated areas, greater data is required from subsea instrumentation, notes Alan Peek, Proserv’s VP for subsea controls and communications.

Longer step-out distances between subsea fields and host facilities also mean that improved communications and power technologies are needed to enable production in remote locations, he adds.

The new product, said Peek, is "effectively the brain of the subsea and control operations because unlike other tools, it controls all of the communication systems and enables the power, speed and accessibility necessary for the control and monitoring of challenging subsea infrastructures and environments.

“What sets A2G apart is the way in which it manages information and power and the sophisticated way that it configures and communicates the data while at different rates. This new technology has already generated an extraordinary level of industry interest and we expect a strong uptake.”

Earlier this year, Proserv announced two separate contract wins with Noble Energy and Talos Energy in the Gulf of Mexico where the A2G system is to be implemented on Noble Energy’s Gunflint field in the Mississippi Canyon area as part of work to control two deepwater wells about 70 miles from the Louisiana coast.
Thursday, 06 March 2014 09:09

GE claims subsea connector advance

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Subsea production systems employ connectors to attach hydraulic lines and other associated equipment to each other.

Traditionally an MQC, or ‘stab plate,’ with screw threads—much like a household nut—is installed on subsea structures and the cables and leads are then attached—much like a household bolt. These connections are key to the overall reliability of the subsea distribution system.

Over time the corrosive, high pressure subsea environment can lead to degradation of the threads, with frequent connection failures experienced by installation contractors and operators during life of field.

The result; a connection system that proves easy to attach when new, but often very difficult to de-couple after years of service during required maintenance or equipment replacement. This, in turn, translates into longer staff hours for service, more effort, more downtime—and higher costs.

After working closely with customers to identify issues posed by connector models with traditional stab plates, GE’s UK-based subsea engineering team re-desiged the technology and removing the screw threads in their entirety—which is an industry first.

The resultant FLX360 is an innovative solution that reduces the corrosion and connection seizure issues previously experienced due to marine and calcerous growth; a common and costly problem. GE has also reduced the number of moving parts that would typically be located subsea for the life of the equipment, from 16 to one.

The design of the FLX360 adopts a mechanism comparable to that seen in a bayonet fitting on a light bulb. In this type of threadless design, small pins are located on the side of the unit that is to be attached. When a remote operating vehicle (ROV) mates the unit to the base, the ROV then rotates it so that the pins catch and lock.

Guidance features on both the tool and stab plates help to avoid any angular, rotational and lateral misalignment possibilities, giving the operator the most ‘room for error’ on the market today.

The new design is "a clear example of common-sense engineering ... stab plates are a critical component which, once engaged, are held together by a huge force," said Paul White, director-subsea technology at GE Oil & Gas Subsea Systems.

"They should remain in position regardless of external conditions for many years, but should also be able to be ‘de-mated’ on demand," he added. "[This] significantly reduces risk, removing the reliability issues in this key aspect of our customers’ operations.”

By removing the vulnerable moving parts typically sited within the subsea component and locating them within the installation tool itself, the connection system can be exercised without disconnecting hydraulics.

The solution, adds GE, allows the provision of clear information to the operator during tool engagement and facilitates improved ease of recovery for servicing purposes.

Wednesday, 05 March 2014 13:04

UK advances Peterhead CCS project

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The UK government has now confirmed that it will fund front end engineering and design (FEED) studies for the Peterhead carbon capture and storage (CCS) project. The FEED work is expected to continue until 2015, and the project to be up and running by 2020.

The project is designed to capture, compress and transport by pipeline one million tonnes a year of carbon dioxide from the Aberdeenshire facility to an offshore gas reservoir for long-term storage beneath the North Sea.

The project is led by Shell, which recently signed an agreement with the UK Government to progress the scheme to the next phase of design. The project, which has strategic support from SSE  - owner of the Peterhead gas power station -could represent the first industrial-scale application of CCS technology at a gas power station anywhere in the world.

"The signing of this agreement is a hugely important step towards the UK delivering the world’s first CCS demonstration facility on a gas-fired power station. The project has the potential to make gas, already the cleanest burning fossil fuel, even cleaner,” said Ed Daniels, chairman of Shell UK.

The proposed initiative at Peterhead is part of a portfolio of CCS projects supported by Shell. Others include the Quest oil sands project in Alberta, Canada, and the Gorgon project in Australia.  

Another key player is Atkins, the technical advisor to the DECC CCS programme to develop and deploy full-chain CCS demonstration plants.  It has provided technical and commercial advice and support to DECC throughout the negotiations of the risk-reduction-phase contracts with the two preferred bidders (White Rose and Shell).  

Atkins is to provide advice and review of the engineering and designs across all technological elements of the CCS chain from the Peterhead power station, carbon capture and gas processing, transport and underground storage of the CO2. Its remit also covers the consenting process and commercial aspects of the programme delivery.

David Few, director at Atkins’ energy business, said: “This announcement follows the government’s commitment to funding the FEED study at White Rose CCS project in December last year and signals a major step forward in the commercialisation of CCS in the UK."

Meanwhile, Shell UK Ltd has awarded Technip a contract to provide front-end engineering design (FEED) for the onshore elements of the Peterhead demonstration project in Aberdeenshire, Scotland.

The FEED scope includes a grassroots carbon capture and compression plant and modifications to an existing combined cycle gas turbine power plant.

Technip's operating centre in Milton Keynes, UK, which executed a pre-FEED study for the Peterhead CCS project about 18 months ago, will execute the FEED for this next phase.

This office serves as a centre of excellence for the development of end-to-end solutions for carbon capture and sequestration projects.

Project details

The Peterhead CCS Project is part of the UK Government’s CCS Commercialisation Competition and in March 2013 was shortlisted as one of the two preferred projects bidding for funding.

The Peterhead CCS project is based on post-combustion capture and will use amines to absorb the CO2, a method that has been used by the industry for around 50 years. It is therefore a mature and cost-effective solution. It has already been demonstrated as feasible, having been deployed in several small installations in the USA and it is recognised as the best available technology for post-combustion CO2 capture.

Following feasibility studies on a variety of options, Shell proposes to build a short length of new pipeline from Peterhead Power Station and link this into the existing offshore pipeline from St Fergus to the Goldeneye reservoir, approximately 12 miles (20 KM) from shore.

CO2 will be stored in the depleted Goldeneye reservoir, which lies about 62 miles (100 KM) from the shore in the outer Moray Firth, and 2.5km beneath the seabed. The reservoir has the key geological features necessary for storing CO2 permanently: a body of high-quality porous rock overlain by impermeable rock to seal the CO2 in place.

Goldeneye was a producing gas field from 2004 to 2011. Injection is the reverse of production: during production, natural gas was drawn from the rock and naturally replaced by salt water; injection of CO2 will drive the salt water back out of the store and into the adjacent rock formations from whence it came. The Goldeneye gas store will be monitored throughout its life.

While most of the infrastructure for the project is already in place, construction is expected to create between 100 and 150 jobs. When operational, the proposed project is expected to support 20 to 30 jobs over a ten-year period.

Wednesday, 05 March 2014 12:36

Fortum partners to develop wave power in the UK

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Fortum has signed a leasing agreement with UK-based Wave Hub in order to test wave power solutions off the coast of Cornwall. The agreement provides Fortum with a new opportunity to rapidly deploy advanced, full-scale wave power converters in ocean conditions.

The Wave Hub facility offers Fortum an opportunity to test wave power converters in favourable ocean conditions. The site is consented, constructed and grid connected, which significantly reduces the time it takes to get devices into the water. The berth that Wave Hub will provide is capable of handling up to 10MW installed generation.

“This is as much ‘plug and play’ as it gets when it comes to wave power generation development. The site already has everything we need to start testing,” says Fortum's chief technology officer Heli Antila, PhD. “From the very beginning, Wave Hub has been very supportive of our project development, which is important as this is a testing environment.”

“One wave power solution that we are currently evaluating to be deployed at the site is the ‘Penguin’, developed by Finnish wave power company Wello,” says Heli Antila. “This technique comprises vessels that float on the water and capture kinetic energy, which is then turned into electrical power, with minimal anchoring attached to the bottom,” she concluded.

Fortum has been involved in wave energy development since 2007 and has participated in the development of several technologies. One of these is the Finnish AW-Energy’s WaveRoller technology, which has been successfully tested off the coast of Portugal.

Last year, Fortum also signed a cooperation agreement with the French marine technology company DCNS to further test and develop AW-Energy’s technology off the coast of Bretagne, France.

In Sweden, Fortum and Seabased AB are currently cooperating around a 10-megawatt wave power park on the west coast of Sweden, in Sotenäs. It is one of the world’s largest wave-power demonstration projects and will start production during 2014.

The technology of choice in Sweden is Seabased's linear wave power generator that is placed on the bottom of the sea.

Wednesday, 05 March 2014 12:13

Pump package to Russian longwall coal mine

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Mining equipment supplier the Kopex group is delivering a turnkey solution for the Vladimirskaya longwall coal mine in Russia.

Part of this project is the powered roof support system to be installed at the coalface itself. Kopex has awarded the supply of the critical pumping systems to RMI Pressure Systems Ltd., based in Manchester, UK.

The Kopex Group is, amongst other things, a manufacturer of powered roof support systems which delivers products into the most demanding markets, including China, Russia and Australia. These systems are specifically designed to provide roof support structures for longwall coal mining.

A crucial part of these systems is the pumping system, which must have completed rigorous testing before being deployed in the field to ensure the safety of the miners operating the equipment.

The practice of longwall mining has been developed and refined with the use of hydraulic roof support systems, which provide support at the coalface to allow the shearer to cut the coal from the seam. Each support can weigh 30-40 tonnes and be rated at 1000-1750 tonnes and also have the ability to hydraulically advance itself 1 metre at a time.

As the roof supports advance, so the roof of the mine is allowed to collapse behind them and the shearer continues to pull the coal from the seam. This all makes the roof support system of critical importance to the mining operation and to the safety of the miners involved in operating the machinery. Any equipment which is selected to operate in this hazardous environment must be proven in reliability and require a minimum level of maintenance.

The efficient operation of the roof support system directly affects the productivity of the mine and any down-time on the system in such a difficult operating environment would be very counter-productive. The reliable performance of these systems is essential if the client is to maximise output from the mine and return on investment.

Power source

The roof support systems require a power source and this takes the form of a sophisticated hydraulic pump capable of producing extremely high pressures. The reliability of these pumps must also be beyond any doubt and bench testing has to be carried out for thousands of hours to ensure their operation in the mine will be faultless.

In this case, Kopex has selected RMI Pressure Systems, which has a proven track record in the mining industry and has considerable experience in supplying equipment for the longwall mining operation.

RMI has delivered three Trimax S300 pumps to power the roof support system, each capable of providing 244 litres/min at up to 353 bar, as well as two of Trimax S300 pumps for the water pumping system, which are cable of providing 319 litres/min at up to 92 bar. The entire contract also includes a service and spares package as well to ensure continued reliable service.

In 2012, the Russian government approved a long term investment plan for the coal industry, with $123 billion to be invested over the next 17 years. This is deemed necessary to meet the future requirements for coal which is used to generate 25% of the electricity requirement in Russia.

With coal production from the underground mines expected to increase by nearly 50% over the next 20 years, the prospects for future contracts within the Russian coal industry are looking good, said RMI.
Wednesday, 05 March 2014 12:08

Shell network event for Brent decommisioning

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Shell UK E&P is holding a decommissioning networking lunch focused on the Brent Project on 15 April, Hardwick Hall Hotel, North East England.

The event will feature a presentation from Austin Hand, general manager decommissioning & restoration, Shell U.K Exploration & Production, who will give and update on the project.

Decommissioning of the Brent field (50/50 Shell/ExxonMobil) is one of the largest decommissioning projects in the North Sea with the scope comprising four platform topsides, three concrete substructures referred to as GBSs, one steel jacket, 154 wells tom plug and abandon and some 36 pipelines to decommission.

Three platforms are still in production; the fourth, Brent Delta has now ceased production. Work is underway to engineer down, in readiness for topsides removals of Brent Delta in 2016.

The project is  planning to submit a single field wide decommissioning programme to the UK regulator DECC  during 2014. 

While companies continue to invest heavily in the North Sea  other mature assets are reaching the end of Field Life.  Over the next 20 years or so more than £30 billion pound will be spent on Decommissioning in the North Sea.

Wednesday, 05 March 2014 11:48

Jacobs JV nets Shell ONEgas extension

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Jacobs Engineering Group Inc. has announced recently that its AJS joint venture with AMEC and Stork has secured a contract extension to continue providing integrated services to the Shell ONEgas Southern North Sea (SNS) asset base.

Shell ONEgas is a combined business unit of Shell UK Exploration & Production (Shell) and the Nederlandse Aardolie Maatschappij B.V. (NAM).

Under the terms of the contract, AJS is providing integrated engineering and project management services for maintenance, modifications and capital projects.

The work is executed offshore on 54 assets in the Southern North Sea, and onshore at gas plants in Bacton in the UK and Den Helder in the Netherlands.

Around 1,250 personnel are employed by the joint venture across the assets, and from office locations in Great Yarmouth, UK, and Leiden, Netherlands. Working as an integrated team, the AJS joint venture has successfully delivered multiple services for Shell ONEgas since 2003.

“The contract extension builds on our long-term relationship with Shell and NAM in Europe,” said  Mark Bello, Jacobs group vice president.

Wednesday, 05 March 2014 11:34

UK offshore industry must get it together

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A new blueprint for oil & gas production on the UK Continental Shelf (UKCS) has been set out by the Wood Review, which maps out a new stewardship regime for the industry.

The report, issuedon 24 Feb, targets the recovery of an extra four billion barrels of oil equivalent - worth £200 billion - on the UKCS over the next 20 years.

Towards this goal, the UK government is to establish a new regulatory body to enforce greater co‐ordination of activities across the industry. This will include collaboration in areas such as exploration, third-party access to infrastructure, production efficiency and decommissioning.

A model for this approach is Norway's Exploration and Production Information Management (EPIM) association - a non-profit organisation governed by the operators on the Norwegian Continental Shelf.

Owned by 40 major oil companies, EPIM's remit is to facilitate IT-based solutions and services for the oil & gas industry through standardisation of requirements and processes.

Around 150 companies - authorities, contractors and suppliers - use the association's services. These are provides via a private Cloud-based system and include hubs dedicated to areas including environmental management, safety training, license administration, equipment information and logistics tracking.

These collaborative platforms improve the quality and flow of information, and lower costs for each individual operator, according to Ove Ryland, executive director of EPIM. They also, he said, introduce best-practice in life-cycle information management.

Moreover, these gains are being achieved "without impacting competition between companies or joint ventures or any reduction in information security," Ryland emphasised at the SMi E&P Information and Data Management conference in London on 12-13 Feb.

"[Collaboration] can be done, it has been done, and needs to be done to ensure a cost-effective and information management-efficient oil & gas industry," said Ryland.

The EPIM director concluded, though, by warning that "there is no point in collaboration and standardisation if you continue to do things the 'old' way or its not implemented properly across the organisations."

This level of industry-wide collaboration will, therefore, require new approaches to data-management at the oil & gas majors - as seen at Shell, which has recently formalised how information is processed throughout the organisation.

"The Shell data model is unambigious, system-agnostic, business-owned and is enabling our senior people to inform, discuss and articulate KPIs," Johan Stockman, an IT leader at Shell Global Solutions, said at the SMi conference in London.

At Shell, experienced, senior managers are now responsible for ensuring that the definitions in the data model actually reflect the requirements of their particular business area. They must, for example, specify what is meant by particular KPIs for well-injection performance, rather than assume that everyone will know what they mean.

"It all comes down to defining what you need," explained Stockman. "If you havn't thought this through, how are you going to have a successful application that you will be able to deploy?"

The increasing emphasis on data-management is closely linked to the digital oilfield concept in which IT and control and instrumentation technologies are combined within the enterprise data system. With their capacity to analyse large volumes of data, these systems give managers and engineers real-time access to engineering data and operational metrics.

The system is supported by production-level technologies as seen, for example, at Ithaca Energy (UK) Ltd, which is using a digitally enabled well performance monitor (WPM) from Honeywell Process Solutions (HPS) at its Athena oilfield in the UK North Sea.

Using WPM, Ithaca’s engineers can monitor how their wells are performing, while visual models predict what each well is capable of producing. Summary information and KPIs from real-time process data historians, production databases and engineering well models, allow operators to track field performance data and manage equipment assets.

The large flows of data generated by such digital oilfield systems is, meanwhile, increasing the need to connect offshore platforms with onshore bases via wireless and mobile networking and satellite communications.

According to a Deloitte report, these trends will drive demand for remote wireless sensors to monitor parameters such as temperature and pressure changes in the oilfield. The information, it notes, is increasingly being monitored by specialist engineering teams based at remote centres dedicated to tracking multiple offshore facilities.

Demand for such capabilities is driving M&A activity in the process control sector, as seen with Rockwell Automation's recently announced acquisition of vMonitor -  owner of the world’s largest installed base of wireless wellhead monitoring systems, with more than 6,000 well sites.

The company’s technologies include an all-wireless portfolio of wellhead sensors and transmitters, remote terminal units, gateways and modems, as well as turn-key monitoring and control systems and services for oil & gas wells, pipelines, pumping and lift stations.

Some observers, though, believe the UK sector could do much more to leverage existing installed base of intelligent instruments. These already comprise the vast majority of the field devices employed in offshore oil and gas production fields.

According to figures from Emerson Process Management, up to 90% of the diagnostic data generated by this equipment is stranded in the field and never used. By integrating technologies that are in many cases already in place, production companies can utilise the diagnostic data acquired from smart field devices and digital valve controllers to improve operations and safety, the vendor believes.

Indeed, perhaps, the biggest lever for the digital oilfield and collaboration between operators on the UKCS will be the industry's commitment to safety - as defined by the many policies and practices adopted in the wake of the Deepwater Horizon disaster in the Gulf of Mexico.

This is acknowledged in the Wood report, which concludes: "Industry has achieved very successful collaboration on health & safety and there is no reason why this cannot work just as well in areas such as production efficiency, deployment of new technologies, shutdown co-ordination and a collaborative approach to decommissioning."
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