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Bringing you the latest innovations in exploration, production and refining Issue 32
April 2015
Full-tilt
Is AgustaWestland’s AW609 TiltRotor the future of offshore transport? Page 30
In the pipeline
Our Q&A tackles pipeline efficiency and inspection Page 12
Joint venture
Radyne’s Merlin system speeds up field joint coating Page 17
OTC here
A look ahead to OTC’s latest innovation event Page 22
ith nt w me w it e 34 o N cru pag e re se
InnovOil
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Inside Contacts: Media Director Ryan Stevenson ryans@newsbase.com Associate Director of Business Development Andrew Stalker andrews@newsbase.com Media Sales Manager Riley Samuda RileyS@InnovOil.co.uk Media Sales Manager Gary Paterson garyp@InnovOil.co.uk
NewsBase Limited Centrum House, 108-114 Dundas Street Edinburgh EH3 5DQ Phone: +44 (0) 131 478 7000
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and refining in exploration, production
April 2015
Issue 32
Full-tIlt
Core questions
12
Merlin weaves magic
17
Strength under pressure
18
Terminal viscosity
20
Kongsberg’s camera
21
OTC’s Next Big Thing
22
All riser with Aquaterra
24
Showcasing innovation
26
Seamless supply
28
Flying full-tilt
30
Pipeline experts identify key challenges and innovations
Radyne Offshore’s Merlin Field Joint Heat & Coat system slashes the time needed to protect pipe welds from corrosion
A brand new event, d5, looks to bring together creative and innovative minds
Inter-industry collaboration and £11 million for UK innovation at ITF
How global standardisation within the offshore market can save time and money
Is AgustaWestland’s AW609 TiltRotor the future of offshore transport? Page 30
The AgustaWestland AW609 TiltRotor can fly at twice the speed and range of a helicopter. Could this be the future of offshore transport?
lIne In the pIpepipelin e
Our Q&A tackles efficiency and inspection Page 12
ure JoInt ventsystem
Radyne’s Merlin speeds up field joint coating Page 17
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Aquaterra’s Riser Monitoring System (RMS) offers a unique, robust method to provide real-time information
www.newsbase.com www.innovoil.co.uk
A look ahead latest innovation event
News in brief
Researchers at Rice University have developed a method to detect and measure asphaltene in crude
Editor Andrew Dykes andrewd@newsbase.com
otC hereto OTC’s
5
3M™ Glass Bubbles are high-strength, lightweight additives used to increase buoyancy and help equipment survive as drillers push the industry to new depths
Design & Web Dan Bell Danielb@newsbase.com
ations Bringing you the latest innov
A note from the Editor
Ith t w en 4 w Itm e3 o u n Cr e pag re se
Recruitment 34 Contacts 35
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By attending this pivotal event you’ll have the opportunity to: • Network with confirmed attendees from Statoil, BHP Billiton, BP, Maersk, Total, Eni, Hess, Shell, Petrobras, amongst 100+ senior flow assurance decision makers, operations engineers and asset managers • Pinpoint the gaps in your flow assurance strategies, enhance your subsea systems architecture and improve your overall production economics and uptime • Learn how Operators are dealing with Flow Assurance issues and the practical solutions for Hydrate, Wax, Asphaltene, Scale, Sand mitigation, Prevention and Remediation • Enhance your operations strategy and increase uptime, avoiding disastrous Flow Assurance issues that could shut in your wells, pipelines and flowlines
The exhibition draws the highest calibre of talent and expertise in the industry in a concentrated, easy to meet manner Joel Wittenbraker, CEO, Mactech Offshore
SUBSEA MACHINING SOLUTIONS
OFFSHORE
Adam Minkley Director - Oil and Gas Upstream Intelligence Phone: +44 (0) 207 375 7239 US Toll Free +1 800 814 3459 Ext: 7239 Email aminkley@upstreamintel.com/flow-assurance
InnovOil readers, enter 2755INN when registering to save an extra $100
www.upstreamintel.com/flow-assurance
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A note from the Editor There is a tendency to think of innovation and innovative technology as the latest, shiniest bit of kit. While the industry is dominated by mammoth engineering projects and eye-watering investments, many innovative ideas can simply be a better way of doing the same thing. This month’s Q&A, examining pipeline efficiency, highlights some prime examples. Although our participants suggested more research and innovation was needed on inspection methods for unpiggable pipes, there was also a broad consensus that operators were becoming more efficient by better using existing techniques, and not through breakthrough engineering. Many of our featured innovations this month follow this pattern. Radyne’s Merlin system speeds up the process of field joint coating by up to 10 times – offering a significant increase in the time taken to complete the pipe-laying operation. Likewise, 3M™ Glass Bubble technology has been around since the 1960s, but its application to oil and gas equipment and infrastructure has remarkable benefits even now. As deepwater drilling advances, these microspheres can be used in coatings offering exceptional insulation on pipelines in very cold waters. Aquaterra has also developed a novel Riser Monitoring System, or RMS, to measure riser strain and predict fatigue. Similarly, applying knowledge and practices from outside the oil and gas industry can often deliver incredible results. Earlier in the month I attended the ITF Technology Showcase, an event very much on the frontline of bringing
new innovations to the attention of the market. However, the unquestionable highlight of the day were the cross-industry presentations. Speakers from the automotive, aerospace and defence sectors – among others – illustrated what could be learned by following successful research models and adopting new technologies. In particular, the National Composites Centre’s Technology Director, Professor Mike Hinton, urged engineers to “think holistically,” and consider the possibilities of composite structures; structures can be made without joints, curved, or rust-resistant – whatever the application may require. Continuing the theme of left-field creativity and inter-sector innovation, Houston’s Offshore Technology Conference is also launching a new follow-on event this year. Featuring speakers from the tech, business and climate sector, the d5 event aims to inspire some creative thinking to consider “The Next Big Thing” in oil and gas. That said, the issue wouldn’t be complete without at least one innovation with an undeniable “wow” factor. AgustaWestland’s AW609 TiltRotor can perform vertical take-off and landing (VTOL) like a helicopter, but its tilting nacelle design and pressurised cabin give it the flight ceiling, range and speed of a fixed-wing aircraft. Its versatility and performance could transform the future of offshore crew transport, and a development agreement with Bristow Group suggests the process has already begun – find out more inside. The team and I are pleased to present the April edition of InnovOil, from NewsBase.
Andrew Dykes Editor
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News in brief
Africa to drive BP’s year Three of BP’s four major projects due on stream this year will be in Africa, the company disclosed in its annual report, filed last week with US regulators. Two projects are to start up in Angola and one in Algeria, while the fourth is in Australia. BP’s African production in 2014 reached 222,000 barrels per day of oil and NGLs, with 181,000 bpd coming from Angola. Gas production reached 14.5 million cubic metres per day, with Egypt accounting for 11.5 mcm per day. Production costs reached US$13.37 per unit – measured in barrels or thousands of cubic feet – in Africa, ahead of BP’s group average, at US$12.68, but below levels in Europe, the US and the “rest of Asia”. Total exploration expenses of US$3.63 billion were recorded for the year, with US$524 million of that related to Algeria, US$110 million from Angola and US$83 million for Morocco. BP also took an upstream impairment charge of US$6.74 billion for the year, which included US$859 million from its PSVM development in Angola. The Angolan charge was driven by near term lower prices, technical reserve revisions and estimated decommissioning costs.
Operations Greater Plutonio Phase 3 and Kizomba Satellites Phase 2 are the Angolan projects, while the In Salah gas southern fields is the Algerian project. Angola LNG, though, will not reach a full restart until 2016, which is a disappointment as it had been expected online by the end of 2015. Angola also provided one of the major start-ups of 2014 for BP, with its involvement in the CLOV development. The company confirmed it had reached its 160,000 barrels of oil equivalent per day plateau. BP reported five discoveries had been made in 2014 that were potentially commercial, of which two are in Africa. One was the BG Group-operated Notus well, in Egypt’s El Burg concession, while the other was the Orca well in Angola’s Block 20, operated by Cobalt International Energy. The Orca-2 appraisal well is being drilled. A first well is also being drilled on Angola’s Block 24, at the Katambi-1, it said. The company did reach first gas production from the DEKA project’s Denise South-6 well, offshore Egypt, in August. DEKA focuses on the Denise and Karawan gas fields in the Temsah concession. The super-major also began drilling a high-pressure high temperature deepwater exploration well, the Atoll-1, in Egypt’s North Damietta concession in September. Performance is ahead of target, it said, with
completion expected in the second half of 2015. BP’s Libyan exploration is under pressure, though. The company holds an 85% stake in the onshore Ghadames and offshore Sirte basins, under an agreement with the Libyan Investment Authority (LIA). BP declared force majeure in August, owing to security concerns, and should this run for two years the company’s deal may expire. Edited by Ed Reed edreed@newsbase.com
Chinese yards see rigbuilding orders drop Chinese yards received fewer orders for offshore drilling rigs and support vessels in 2014, reflecting a decline in offshore oil and gas exploration and development as well as a rig surplus. Orders booked by Chinese yards last year dropped 52% year on year to 167 units, or 40% of total orders worldwide, according to China Shipbuilding Industry Research Centre. Of the new orders, 47% were for drilling rigs, including 14 jack-ups and five semisubmersible rigs, and 50% were for offshore support vessels (OSVs).
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News in brief
The country’s top yard by order value was CIMC Raffles, which booked US$4.1 billion worth of orders. It was followed by China Merchant Heavy Industry, with orders valued at US$4 billion. Industry sources have said a growing number of rigs are being cold-stacked as exploration activities decline on the back of weaker oil prices. Semi-submersible rig specialist CIMC Raffles is looking to the domestic market for orders from offshore companies and service providers, such as CNOOC Ltd and China Oilfield Services Ltd (COSL). Most of the rigs under construction have been ordered on a speculative basis, with owners paying a deposit to shipyards before looking for rig charters. Chinese yards have traditionally gained an edge on their Singaporean and South Korean rivals by offering attractive financial terms with low first tranche payment. Under such terms, Chinese yards are responsible for securing financing for the rest of the fabrication, while rig owners must supply key equipment such as the drilling equipment package and blowout preventers (BOPs). This practice has boosted orders while leaving the yards carrying huge financial risks. With crude prices much lower than this time last year, owners are finding it extremely challenging to find employment for rigs under construction, increasing the risk that they might abandon the rigs if they fail to secure charter agreements with drilling companies. Edited by Andrew Kemp andrew.kemp@newsbase.com
Mixed response to UK tax cuts UK Chancellor George Osborne announced a raft of measures aimed at revitalising the country’s ailing North Sea sector on March 18. Yet while the steps, which include the complete removal of the supplementary charge he introduced in 2011, have been broadly welcomed by the industry, fears remain that this will not be enough to halt the current wave of job losses and stalled projects. In his final Budget before May’s general election, Osborne responded to the calls to address the rapid deterioration of activity on the UK Continental Shelf (UKCS) that has occurred since the collapse in oil prices late last year. Primarily, he said the government would reduce the supplementary charge on oil and gas companies, levied on top of a 30%
corporation tax rate, from 30% to 20%. This change was also backdated to 1 January. This marks a complete reversal from the Chancellor’s 2011 budget, which introduced the 12% charge – a move that has been blamed in part for the 18% fall in UK oil and gas production that occurred the following year. In December, this was lowered by 2% in Osborne’s Autumn Statement, a move that was criticised for not going far enough by many of the region’s operators. This time, much more far-reaching incentives have been introduced. Along with the abandonment of the supplementary charge, the petroleum revenue tax, which is levied on profits from fields developed before March 1993, has been cut from 50% to 35%. An investment allowance will come into force that simplifies the current system of variable arrangements for different North Sea fields. In total, Osborne said the new measures were worth GBP1.3 billion (US$1.39 billion) to the industry over five years, and would raise production by 15% by the end of the decade. “Today’s new fiscal measures together with the rapid creation of the Oil and Gas Authority [OGA] demonstrate the government’s support for the industry and its recognition that the UK must be in a position to compete effectively with other basins around the world,” said Andy Samuel, chief executive of the OGA, the new regulator. “Industry must now move quickly to create a more competitive cost base and improve production efficiency in line with the goal of maximising economic recovery of the UK’s oil and gas resources. The OGA will actively support this work and monitor progress closely.” This view was echoed by Uisdean Vass, a partner at law firm Bond Dickinson, who said that the reduction of the supplementary tax rate to 20% and the investment allowance changes “will give greater security to the 380,000 jobs in the sector as well as helping arrest the decline in investment that we have seen over the past few years”. “The industry has been hit hard in recent months by record-high investment costs combined with a slump in global oil prices. The chancellor’s statement today will have given the sector much needed hope for the future,” he continued. But Jon Fitzpatrick, senior managing director at Macquarie Capital and president of the Scottish Oil Club, said the measures were unlikely to have a significant impact. “George Osborne and the Treasury’s decision to introduce tax subsidies to the North Sea oil producers will be very welcome
by the industry,” he said. “However, in reality these concessions will likely only benefit the handful of tax-paying North Sea producers and will not address the much larger, structural issues facing the North Sea oil and gas industry.” These include “a vast number of projects that are unfunded and unsustainable at current oil prices”, while many firms are likely to withdraw from the region altogether. Some critical North Sea infrastructure will also likely be decommissioned, “leaving existing discovered resources at risk of never being developed”. Instead, Fitzpatrick pointed to Norway’s introduction of rebates on exploration drilling, a step that was introduced in 2005 that allows companies to claim 78% of their exploration costs in the case of a dry hole. This has been credited with more than doubling the number of explorers present in Norwegian waters, as well as adding billions of barrels to the country’s reserves. Edited by Ryan Stevenson ryans@newsbase.com
North Dakota producers to see new vapour pressure standard On April 1, a new standard for vapour pressure for North Dakota crude will come into effect. It is designed to improve safety during the transportation of crude from the Bakken shale, which contains more volatile gases than oil even from other shale plays. Under the new standard, Bakken crude will be required to have a pressure of no more than 13.7 pounds per square inch, below the current federal standard of 14.7 psi. Conventional crude has a vapour pressure of about 6 psi. The order requires operators to separate light hydrocarbons from all Bakken crude oil to be transported, prohibiting the blending of light hydrocarbons back into oil supplies prior to shipment. Oil and gas division staff at the North Dakota Department of Mineral Resources (DMR) will conduct field inspections at the well-head to enforce compliance. Operators with oil that is too volatile could face a penalty of up to US$12,500 for each day they are in violation of the new order.
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Even so, the state standard is being scrutinised in light of the recent derailments of trains carrying Bakken crude. Vapour pressure is a measure of volatility, a particular problem with Bakken crude, which represents about 80% of the oil moved by rail in North America because of the region’s lack of pipeline infrastructure. In the most recent crude-by-rail accident, a BNSF train carrying Bakken oil derailed on March 5 in Illinois, catching fire and prompting evacuations. Less than three weeks earlier, a CSX train carrying Bakken crude had derailed in West Virginia en route to a depot in Yorktown, Virginia. The crude on the latter train had a vapour pressure of 13.9 psi, according to a February 10 report by Intertek Group. This would have put it in violation of the new North Dakota standard. Critics say that the new North Dakota standard, however, is still too low. The crude involved in the crude-by-rail disaster in LacMegantic, Quebec, in 2013 – which killed 47 people and caused extensive damage – had a vapour pressure of less than 10 psi, according to media reports. A DMR spokeswoman, Alison Ritter, told NewsBase that the crude measured at Lac-Megantic was not the oil in the tankers that had exploded, and that it was also tested by a method that is known to lower the psi level. North Dakota’s rules will be adequate, she said. Unleaded gasoline – which is handled daily across the US and is considered safe – has a vapour pressure of 13.5 psi, she noted, not much lower than the new North Dakota crude standard of 13.7 psi. Ritter said that North Dakota only had jurisdiction over the well-head, where crude can be processed for volatility. It is up to the federal government, she said, to regulate train speeds, track maintenance and tanker design. Edited by Anna Kachkova annak@newsbase.com
Warwick students take submarine stateside A team of 8 masters level students from Warwick University has taken on the challenge to design and build a humanpowered submarine to compete in the 2015 International Submarine Race (ISR). The ISR will take place in Maryland, USA from June 22-26, with teams from across Europe, Asia and America. Teams will be judged on the merit of their design, manufacture and lessons learned as well as awards for outright speed, agility and innovation. 2015 marks the second year that “Warwick Sub” has entered the race, having placed fourth in the world and second in the UK in 2014. The students hope to build on the achievements of last year by improving the hydrodynamic efficiency of the hull inspired by a unique hydrofoil design, enabling the pilot to travel at far greater speeds. The team are also using the competition as a chance to explore the capabilities of “green” materials and have secured sponsorship to manufacture the hull from a flax fibre composite. The biggest issue the team now face is how to transport the submarine across the Atlantic with minimal funding. Fully assembled, the large submarine renders air freight travel difficult and expensive. Project Leader Richard Freeman explained that: ‘We have managed to reduce flight costs by designing a ‘fold away’ submarine; the chassis can be dismantled
into four sections which fit inside each other, packing to a much smaller volume. We still have the task of raising enough money to pay for our competition entry fees and for the team’s transport to the USA, but we are optimistic given the exciting nature of the project that our new and future sponsors will help us realise our goal!” To find out more about Warwick Sub or to help sponsor the team, please visit their website. WARWICK SUB
Rosneft signs deal with Golar LNG The state-controlled Russian oil and gas group Rosneft has signed a memorandum of understanding (MoU) with Golar LNG, a Bermuda-registered LNG carrier operator and infrastructure developer. In a statement, the company said that the new agreement provided for the two companies to “analyse the possibility of employing Golar’s advanced floating liquefaction of natural gas (FLNG) commercialisation technologies at Rosneft projects.” Golar is a well-established operator in the global LNG shipping market, having been active in the sector for around 30 years. It operates around a dozen LNG and methane tankers, as well as a clutch of newbuilds acquired from South Korean shipyards in recent years. The group has a strong foundation in
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the downstream area of the market. But its strategic objective now is to diversify and become an integrated midstream player in the LNG sector. This will be led by moves to expand into FLNG and floating storage and regasification unit (FSRU) operations. It will use its own GoFLNG technology model in its efforts to move further upstream. Rosneft, for its part, is steadily building up its interests in the LNG market. Until recently, Gazprom, another state-run company, was the only Russian player in this arena. Since the Kremlin began authorising other firms to export LNG in late 2013, though, other Russian groups – including Rosneft and a smaller independent, Novatek – to consider entry into the LNG export market and challenge Gazprom’s dominance in the sector. Rosneft is one of these. It hopes to liquefy gas from fields located offshore Sakhalin Island at the proposed Far East LNG plant and has made arrangements to work with ExxonMobil on the plant. The Western sanctions regime has raised questions about the US giant’s involvement in the project, but Rosneft still hopes to start LNG production in 2018 or 2019. Novatek, meanwhile, is leading the Yamal LNG scheme, which calls for exporting LNG from a liquefaction plant that will be built on Russia’s northern coast. It has granted minority stakes in the project to France’s Total and China National Petroleum Corp. (CNPC). As it seeks to develop its LNG business, Rosneft has found Golar’s experience in LNG carrier fleet management and LNG logistics attractive. Golar, for its part, has described Rosneft as having a “world-class upstream portfolio.” According to Golar, the two companies will enter into discussions on the use of GoFLNG in the Latin American market. The parties are also targeting the “signing of two FLNG tolling agreements for projects within Rosneft’s portfolio’” it said. The new deal is good for Rosneft, which has seen its international ambitions thwarted to some extent by Western sanctions over the last year. For example, the Russian firm dropped plans to acquire Morgan Stanley’s oil trading arm because of compliance problems in the US. But Golar’s Bermuda registration may make Rosneft more confident that it can be relied upon for LNG trading relations without repercussions. Edited by Jennifer de Lay fsuogm@gmail.com
USGS: more data needed on water risks of shale drilling A new study by the US Geological Survey (USGS) says more data is needed to understand the potential risks to water quality associated with the development of unconventional oil and gas development. The USGS researchers said they were only able to investigate long-term water quality trends in just 16% of US watersheds with unconventional oil and gas resources. “There are not enough data available to be able to assess potential effects of oil and gas development over large geographical areas,” said USGS scientist Zack Bowen, the principal author of the article, published in the American Geophysical Union’s Water Resources Research. The agency reviewed national water-quality databases from 1970 to 2010. The US does not have a national waterquality monitoring programme that focuses on oil and gas development. The researchers therefore had to use existing national water-quality databases. Data on hydraulic fracturing were also used to assess trends in water quality in areas of oil and gas development.
The study found no widespread and consistent trends in water quality, such as evidence of chloride and specific conductance in areas where unconventional oil and gas wells are prevalent. Specific conductance is a measure of ions in water, which will have originated from the breakdown of compounds. Existing national databases do not have enough water-quality samples from different locations, said the researchers. Nor have enough of their constituents have been measured, they said. Fracking has been blamed for tainting water supplies, often owing to the spillage of wastewater on the surface, or through its disposal in or near aquifers. However, in one set of results reported last year for Greene County, Pennsylvania, the US Department of Energy (DoE) found that fracking chemicals stayed far below an aquifer. In a second study by independent researchers and environmental groups, which was also reported in 2014, it was faulty construction in some of 133 wells that was found to have polluted drinking water in both Pennsylvania and Texas – it was not the fracking process itself. Fracking had been carried out 1 mile (1.6 km) from drinking water sources. The cause of contaminated drinking water in Pavillion, Wyoming has been harder to pin down. Fracking had been carried out near the surface, and chemicals were found in wells of potable water. The fracking process could
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be to blame in this instance, or it could be well integrity or disposal pits. The incident, which was initially studied by the US Environmental Protection Agency (EPA), is now being looked at by Wyoming officials. Edited by Anna Kachkova annak@newsbase.com
Fugro expands AUV fleet with delivery of Echo Surveyor VII Fugro took delivery of the Hugin 1000 Autonomous Underwater Vehicle (AUV), the Echo Surveyor VII, in December 2014. Depth rated to 4,500 metres, the new AUV now holds the record for the deepest Hugin AUV dive, surveying in water depths surpassing 4,200 metres. As the latest addition to Fugro’s AUV fleet, the Echo Surveyor VII is specifically designed for high resolution and efficient survey operations in water depths reaching 4,500 metres. The extended depth rating of the Kongsberg Hugin 1000 AUV places it in the most advanced ranking of deep sea survey instrument platforms, and it can be mobilised for rapid deployment to suitable vessels of opportunity in a range of worldwide project locations. Representing state-of-the-art development, the Echo Surveyor VII houses an instrumentation payload ideal for geochemical hydrocarbon seep exploration and produces data with enhanced resolution and increased quality. The AUV provides improved multibeam swath coverage and supports the acquisition of side scan sonar, sub-bottom profiler and CTD profiler data. In addition, it offers rigorous internal navigation for accurate and efficient data collection. Fugro operates one of the largest fleets of commercial AUVs in the world and has applied this technology in some of the most complex and challenging deepwater surveys. The Echo Surveyor VII recently joined three of Fugro’s specialist survey vessels in the search for the missing Malaysia Airlines flight MH370, in the Southern Indian Ocean. The new design features of this AUV are particularly suitable to support this exceptional mission, including the high-resolution camera capability to provide positive verification as required.
The addition of the Echo Surveyor VII further advances Fugro’s fleet of high quality geophysical and remote sensing survey instrumentation. As the ultimate choice of instrument platform for deep sea and remote surveys, this newest AUV highlights Fugro’s commitment to remain at the forefront of industry advances with recognised, worldclass technology and expertise. FUGRO
Data obtained will be transmitted from the UAV in real time, and also recorded on a memory card. Operators can change the flight trajectory, return the drone to a desired point, and photograph any object again. Tomskneft specialists will decide on the further use of the machines on the basis of initial testing. Unmanned aerial vehicles are already in use at one of the most significant E&P enterprises of Gazprom Neft, Gazpromneft Noyabrskneftegaz. GAZPROM NEFT
Cortec® Middle East launches partnership in Saudi Arabia Pipeline reliability improved at Tomskneft Tomskneft VNK has begun using unmanned aerial vehicles (UAVs or “drones”) in monitoring its pipeline routes and oil and gas production facilities. Testing of domestically produced “drones” has been initiated at the Sovetsky and Vakhsky fields, located in the Strezhevsky region. Given the extent of the territory covered by the company, the use of UAVs addresses a number of tasks: improving the monitoring of pipeline condition and status, and allowing the identification of trespassers within the buffer zone. In order to fulfil these functions the UAVs are specially adapted for photo and videorecording. Apart from video surveillance, infrared (thermal) imaging will also be used in patrolling. A drone can cover an area of 30 square kilometres in one hour. Flight duration averages two and a half hours, and cruising speed 70 kilometres per hour. Equipment has been adapted for usage in Siberia, and can be used in temperatures as low as minus 30 and as high as 40 degrees.
Cortec® Middle East continues to strengthen and expand its regional presence in the corrosion control industry with a strategic partnership in the Kingdom of Saudi Arabia. The first integrated corrosion solution partnership between Cortec® Middle East and Abdulla Fouad Impalloy Ltd. Co. (AFIC), the Kingdom’s foremost cathodic protection company, was launched Monday, February 16th, 2015. The event brought 75 representatives from top local educational institutions, major oil and petrochemical operating companies, leading engineering firms, and contracting companies together. Attendees were briefed on the latest advances in the field of corrosion control including Cortec’s Corrologic Solutions for Soil-side corrosion mitigation for Aboveground Storage Tank bottoms (AST), Corrosion Under Insulation (CUI) and Cased Pipeline Crossings (CPC). AFIC and Cortec® ME concluded with attendees feeling well informed and excited about this partnership and its potential impact on the current and future industrial best practices in the field of corrosion control. “We are enthusiastic to begin this partnership with Cortec® Middle East, which will allow us to support our existing wide network of customers with innovative solutions to their corrosion challenges” stated Salman Al-Zayani, BDM of AFIC. “With this partnership, we look forward to further expanding our established presence in the Saudi market in the field of corrosion control and mitigation” commented Khalil Abed, BDM of Cortec® ME. CORTEC
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Ceona awarded rigid pipelay project for Amazon vessel in Gulf of Mexico Ceona, SURF contractor with heavy subsea construction capabilities, has secured a Letter of Intent (LOI) for the company’s flagship field development vessel, the Ceona Amazon. This will be Ceona’s first rigid pipelay project in the Gulf of Mexico for well-established US independent oil & gas operator, Walter Oil & Gas Corporation. The Ceona Amazon will be deployed for the Coelacanth Export Pipelines project with the scope of work encompassing the installation of an oil and a gas export line tying the new Coelacanth Platform into existing pipeline infrastructure. Each 10” line will be approximately 11 miles, totalling 22.6 miles (approximately 36 km). The pipelines will each be terminated by two pipeline end termination (PLETs) structures installed by the Amazon. All work will be undertaken in one single mobilisation. Project Management and Engineering work has started in Ceona’s Houston office with support from the corporate offices in London and Aberdeen. Mark Preece, Ceona’s Executive VP Commercial and Business Development, said: “We are extremely pleased that the Amazon has secured her first contract, with final vessel delivery on time and within budget. This will also be her first rigid pipelay project and we look forward to demonstrating the Amazon’s capabilities in this area. “As such, we would like to thank Walter Oil & Gas for having such confidence in the Amazon and her distinctive, cost-effective capabilities which is a huge endorsement of Ceona’s vision for designing a vessel that takes subsea construction and installation into a new era. The project will be managed from Ceona’s Houston office and the team will ensure Walter Oil & Gas is highly satisfied by the quality of our project execution and vessel performance.” Janelle Pence, Ceona’s VP Commercial Americas, said: “The award of Coelacanth is a milestone for Ceona and fully demonstrates our commitment to the region. We look forward to working closely
with Walter Oil & Gas to deliver a safe and successful project.” Shipbuilding specialist Lloyd Werft successfully delivered the Ceona Amazon less than two years after the letter of intent for its construction was signed. Last month, the Amazon was equipped with her inclined multi-lay VLS with a top tension of 600te, and with two 400te Active Heave Compensated (AHC) masthead cranes able to work in tandem. The two 18m (59 ft) diameter wheels on the top tower and deck are also being installed. All deck installation work has been carried out at the Huisman yard in the Netherlands. The Ceona Amazon will represent the second new vessel – after the Polar Onyx – that Ceona has brought to the market on time and budget. The Ceona Amazon is 199.4m (655 ft) long and 32.2m (106 ft) wide, drawing 8.0m (25 ft) with a gross tonnage of 33,000te. She is due to enter service in March 2015. CEONA
China’s first integrated fullyhydraulic drilling rig made by Kerui Kerui Group’s hydraulic drilling rig KY720 was recently offline, China’s first fullyhydraulic mobile drilling rig integrated with automated wellhead tools, fast moving capability, fully hydraulic drive and compact structure. Hydraulic drilling rigs are mainly used in the development of shallow oil and gas resources. Those resources are mostly located in mountainous areas, making it difficult for cluster well drilling, equipment relocation, automation and drilling cost control, etc. KY720 is completely suitable for the exploitation of shallow resources, which has focused on solving problems such as equipment relocation in the process of drilling. According to KY720 R&D project teams, the drilling rig adopts an innovative design of power supply, overall structure and tool integration, on the basis of meeting 7 international and industry design standards. It has adopted fully hydraulic drive, worldleading diesel engine and transfer case gears,
and load sensing system for power output and control. The KY720 realizes high speed of the power head while keeping the motor load low due to its optimized hydraulic system. In addition, the energy consumption is cut by 30%-40% and operators required from 8 to 3. KY720 has incorporated the stateof-the-art telescoping mast technology, dual-hydraulic cylinder, and wire rope feeding system, substantially optimizing the volume of the equipment for relocation and ensuring its high mobility. Meanwhile, the embedded power catwalk is of great significance in enhancing the level of safety and automation. KERUI
Sir Patrick Brown to chair UK’s Oil and Gas Authority (OGA). Energy Secretary Ed Davey has announced that Sir Patrick Brown will take up the role of chairperson of the Oil and Gas Authority (OGA). Sir Patrick will work closely with Chief Executive Andy Samuel as he continues to build the senior leadership team for the new regulator. The first three directors were announced in February and further recruitment is ongoing Announcing the appointment, the Secretary of State said the establishment of the OGA was a key recommendation of the Wood Review and pointed to the progress made in establishing the regulatory body in a short period of time. “Sir Patrick brings a wealth of experience to this role and his appointment is another step forward in getting the OGA up and running at a crucial time for the North Sea industry which plays a vital role in protecting the UK’s energy security.” Mr Davey said. Sir Patrick said: “I’m very pleased to be joining the OGA and look forward to working with Andy Samuel to make sure the oil and gas industry is in the best possible shape for the future.” The OGA will become an Executive Agency in April this year, and will work with industry and government to maximise economic recovery of the UK’s oil and gas resources. n DECC
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Core questions page 12
April 2015
InnovOil asked pipeline experts to identify some of the key challenges and innovations in the sector right now Global Pipes Summit Survey 2015 134 respondents to all questions
Q1. What is your main responsibility? n Pipeline Engineering & Construction 28% n Project Planing 13% n Pipeline Integrity and Maintenance 22% n Pipeline Operations 15% n Control room management 6% n Others 16%
Q2. Which is the greatest challenge to the successful development and implementation of new pipeline infrastructure? n Availability of finance n Regulatory challenges n Skills shortage n Environmental/technical challenges
13% 21% 13% 53%
Q5. Please specify which of the following situations and configurations you consider the most challenging when inspecting your pipelines. n Multi-diameters 10% n Low-flow conditions 10% n Small diameters with tight bends 21% n Difficult or no access 10% Cased road crossings 0% n Bore restrictions 5% n Back-to-back bends 5% n Unbarred tees, crossovers, dead- legs 5% n Steep and vertical sections 5% n Thick- or thin-walled pipe 10% n Over- or undersized valves 10% n Short-radius or mitered bends 10% Other [please specify] 0%
Q3. Which geographic areas provide the biggest potential for growth for your business? North America 0% Central America 0% South America 0% n Western Europe 23% n Eastern Europe 33% n Middle East 11% n Africa 18% Australia 0% n Asia 15%
Q4. What do you consider as the
Q6. What is the most frequent
n Material Defect 17% n Corrosion 25% Ground Movement 0% Hot Tap by Error 0% n Third Party Activity 42% n Construction Defect 16% Other 0%
Answer Rating Options 1 2 3 4 5 Average Mechanical 1 1 5 0 0 2.57 Operational 1 1 0 4 1 3.43 Corrosion 1 3 2 0 1 2.57 Natural 0 1 0 3 3 4.14 3rd Party 4 1 0 0 2 2.29
main cause for your pipeline failure?
cause of spillage in your pipelines?
April 2015
Guy Dos Santos
Technical Director, Pipeline Integrity. Dpt. Opérationnel Expertise Protection contre la Corrosion, GRT Gaz What are the biggest challenges in terms of risk-based inspection? We have to better manage the progress of inspection and the repair, as well as gaining feedback to on inspection schemes and repairs. The intervals between inspections also need to be optimised. We have to guarantee that the reorientation of inspection and repair does not lead to an additional cost which can make budgets uneconomical. We also need to optimise the methodology of Above Ground Survey Inspection (External Corrosion Direct Assesment) for unpiggable pipes. Internationally, are there issues in terms of different standards and specifications when it comes to piping and inspection? For Above Ground Survey Inspection, there is a standard practice – the “pipeline external corrosion direct assessment methodology” – but countries appropriate it in a different way. Have any new technologies or innovations provided a breakthrough for the sector? SCT Tomography seems to be an innovative and promising solution. Are there any areas where more research or attention needs to be directed? Techniques for the detection of defects on unpiggable pipes. n
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Fidel Espíndola Cruz
Risk Analysis Coordinator, Pemex What are the biggest challenges in terms of risk-based inspection? For me the biggest challenge in is establishing a complete data culture. As a probabilistic approach accurate assessment is completely dependent on good quality data and therefore we must create an appreciation of the power of data and a culture that is based on its merits. Internationally, are there issues in terms of different standards and specifications when it comes to piping and inspection? Yes. Although most of them are based in American and European standards, in this moment most of the countries are creating standards and specifications based in their experience. How can more be done to share knowledge and solutions? The internet is the best option; especially in non-commercial pages, because when a recommendation comes from a specific company, most of people can think that it is just publicity. Have any new technologies or innovations provided a breakthrough for the sector? No. I think the real breakthrough had been the combination of old technologies and procedures, but doing them better and with more accuracy. Are there any areas where more research or attention needs to be directed? Yes, it is crucial that further research is directed towards data gathering, in-line inspection for high temperature pipelines, pinhole detection, UT Guided Waves which can identify metal loss, in-line repair and self-repairing pipelines. n
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Douglas Robertson
TransCanada DSS & Leak Detection Engineering, Leak Detection Technology Initiatives & BD Support Team Lead What are the biggest challenges in terms of risk-based inspection? I think the biggest challenge is the completion of an accurate risk analysis prior to developing the inspection schedule, and then continuing to update that risk analysis as conditions change. How can more be done to share knowledge and solutions? This is a challenge in all aspects of pipeline operation. More transparency is a must. Pipeline operators must work with regulators and the rest of the industry to create central reporting systems to allow all operators to measure themselves against the rest of the industry. Have any new technologies or innovations provided a breakthrough for the sector? None so far, but we are working on some innovative ideas for inspecting unpiggable station piping. Are there any areas where more research or attention needs to be directed? All areas need on going research to continue to improve and advance the industry, and reinforce our social contract with the public to operate these pipelines. n
Answers courtesy of Global Pipe Tech Summit.
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April 2015
Caroline RobertsHaritonov, Director, Astrimar
What are the biggest challenges in terms of risk-based inspection? The main objective of risk-based inspection is to optimise inspection effort/work through better understanding of pipeline condition and management of pipeline failure risk. This allows a reduction in unnecessary inspection for low-risk pipelines/failures and enables maximum efficiency in the allocation of resources, focussed where it is truly needed. Risk is assessed through a combination of the likelihood of the failure event and the consequences if the event occurs. The effective calculation of risk represents one of the biggest challenges in the application of risktbased inspection. To assess the likelihood of pipeline failure, it is essential to have knowledge of the condition of the pipeline, how it has been operated, the threats (or potential failure causes) to which it is exposed, and the change in condition over time. This means it is important to understand and be able to predict degradation mechanisms for offshore pipelines, and the rate of damage accumulation, so that time dependent failures can be accounted for in determining when to next inspect. The uncertainty in the degradation process needs to be accounted for in evaluating against acceptable risk levels. While numerical evaluation of failure probability is not essential, the more effort that is put into desk studies based on known engineering models and pipeline operating data, the more confident the assessment can be and the
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less resources required for carrying out physical inspection. To assess the consequence of failure, it is essential to determine the range of consequence scenarios that could occur, for example, from pin-hole leak to full bore rupture and how these can escalate into more severe consequences, or with efficient response, have the potential to be controlled. Rather than assuming the worst case scenario, an evaluation of the likelihood of each final scenario enables a more realistic assessment of risk and more focused identification of risk priorities. The second biggest challenge in RBI is in determining the frequency of inspections based on the calculated risk. One common misunderstanding is that inspection gives perfect knowledge of pipe condition. The knowledge gained from the inspection is only as good as the inspection technology employed and the post-processing of inspection data gained. For failure modes that are subject to random events, the risk doesn’t vary over time, so a rule of thumb on the frequency of inspections tends to be adopted. For failure modes that are time dependent, the frequency of inspections should relate to the time at which risk reaches the pre-defined acceptance level, although defining the risk acceptance criteria is also a challenge. Internationally, are there issues in terms of different standards and specifications when it comes to piping and inspection? RBI by its very nature is not a prescriptive but a descriptive process that requires evaluation and decision on the most appropriate manner in which to manage risk and the value associated with the risk reduction. Defining RBI in a standard can cause problems in that it can become a prescriptive process. As well as defining the process of evaluating risk and how to make the subsequent decisions, if the standard starts to drive
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the decision making then the value of the risk-based approach may be degraded. The most relevant sets of references are the API Recommended Practices RP580 and RP581 and DNV RP F116; both recommend processes that use riskbased approaches. These Recommended Practices also contain examples of methods of setting inspection frequencies based on assessed risk. The concern is if these examples are taken as prescribed best practice instead of indicative of an adaptive approach. Have any new technologies or innovations provided a breakthrough for the sector? Improved monitoring, data capture and data processing technologies, both for continuous monitoring and discrete inspections, will enable ongoing improvements in the confidence of pipeline condition. This will enable more effective risk management with less reliance on costly and interruptive inspection programmes. Overall continued improvement in risk understanding and management will result in less interruption to operations as a result of planned or unplanned events and drive continued improvement in pipeline efficiency. Are there any areas where more research or attention needs to be directed? The greatest improvements in pipeline efficiency will be gained by having better confidence in pipeline condition without the need for intrusive inspection. Improved capability and reliability of non-intrusive monitoring equipment (for temperature, pressure, composition, pipewall corrosion and strain) combined with continuously improved predictive models, updated with inspection data when available, will enable a significant reduction in pipeline condition uncertainty and hence a reduction in pipeline risk and inspection frequency. n
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Merlin weaves magic on field joint coating Radyne Offshore’s Merlin Field Joint Heat & Coat system slashes the time needed to protect pipe welds from corrosion
I
n offshore pipeline installations, steel pipe sections are welded together on the lay vessel, usually in one- or two-length segments. In most cases, the pipe is protected from corrosion with a first layer of fusion bonded epoxy (FBE) and with additions of layered polyolefin coatings, when applicable. Small sections at either end of the pipe are left uncoated, in order to maintain the integrity of the rest of the coating when sections of pipe are welded together. These areas of welding – field joints – must also be protected from corrosion once the pipe sections are joined, again using FBE, polyolefins, heat-shrink sleeves or urethanes. To achieve this, the welds must be heated before the coating can be applied. Field joint coating is vital to combatting corrosion and maintaining pipeline integrity, but naturally adds considerable time and cost to the operation. Radyne Offshore’s Merlin Field Joint Heat & Coat System combines these processes into a single unit, carrying out both simultaneously. The result is a far more efficient method of protecting field joints. Merlin Integrated induction coils heat the pipe, while low-temperature pyrometers measure surface temperature. Once the surface has reached a pre-determined temperature, the pyrometer will trigger the coating process, during which multiple internal heads apply FBE or copolymers swiftly and evenly. The fully automated system means joints are monitored constantly, increasing accuracy, repeatability and reliability compared to manual methods. The Merlin system gives control to the supervisor, while operators can use pre-selected heating and
coating recipes modelled by Radyne. The Merlin design concept is based on 4 frame sizes, covering 8-inch to 48-inch (203-mm to 1,219-mm) outer diameter pipes and uses interchangeable tooling, meaning it can be reconfigured for various coating applications. As a result, units are not projectspecific but can become an asset to individual vessels, used across several projects dependent on pipe diameter and joint length. The primary benefit of a combination system is a significant reduction in the time taken to process field joints, allowing a faster throughput of pipe preparation prior to laying the pipeline. While a typical field joint coating can take up to 15 or 20 minutes to apply, Merlin can complete the process in as little as 55 seconds on 8-inch pipe and around 3 minutes on 48-inch pipe – typically representing thousands of hours and dollars of saving on a major deepwater project. Heat and power As part of the Inductotherm Group, Radyne also provides clam coils for pipe-heating prior to welding and/or shrink sleeve applications and post-welding heat treatments. End pre-heating coils for treating pipe-ends prior to welding are also provided for stalk prefabrication, both onshore and offshore.
Each induction coil is designed and modelled to heat the field joint accurately – controlling the heat-affected zone and ensuring that the factory-applied coating adjacent to the weld area is not compromised. This also removes the risk of coating disbondment. Radyne’s Flexitune unit – a small versatile power supply – is supplied for use with handheld coils for holiday repair and for aiding the removal of parent coating in preparation for anode tag welding. Radyne Offshore has been supplying induction heating equipment and systems to the offshore pipe lay industry since 1994, primarily to major pipe-lay vessel owners and operators. Its technologies have serviced some of the largest pipe-laying projects in the world, including Blue Stream (2000), Thunderhorse (2002), Mardi Gras (2004), Medgaz (2007). More recently, it has been used in projects such as Walker Ridge, JackSt Malo, Liwan, Guara Lula, Cabiunas, and presently Ichthys and the former South Stream development. n Contact: Inductotherm Heating & Welding Tel: +44 (0)1256 335 533 Email: info@inductothermhw.co.uk Web: http://www.inductothermhw.com
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Strength under pressure
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April 2015
3M™ Glass Bubbles are high-strength, lightweight additives used to increase buoyancy and help pipelines and equipment survive as drillers push the industry to new depths
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s subsea networks become more prevalent, and as drillers push into deepwater and highpressure high temperature (HPHT) conditions, pipe and flowlines also encounter new problems. At low water temperatures, ice-like gas hydrates, asphaltenes and waxes can form quickly, blocking pipes and causing serious flow assurance issues. At new depths of 3,000m, many traditional solutions are too costly or ineffective. Although layered pipe-in-pipe solutions offer the best insulation and longest cool-down times, their weight and bulk mean they can be more difficult and costly to lay, and too heavy to support in deeper waters – a particular concern for risers. As an alternative, wet insulated pipe – consisting of a single pipe coated with syntactic foam insulation filled with 3M Glass Bubbles – is less than half the weight of pipe-in-pipe. This makes it far more practical for use at greater depths and in longer runs, but with comparable performance in terms of overall heat loss. Greater flexibility allows for reeled pipe to be laid rather than field jointing short rigid sections which is expensive and can result in integrity failures.
3M Oil and Gas UK Technical Sales Manager, Darren Hall, highlights that: “In general, you want to use as good an insulator as possible and the advantage is that the lighter the bubble is, the better the insulator it is,” Hall says. “But the downside is that the lighter the bubble is, the weaker it is. So you want one which is strong enough to survive [the pressure] but has the best insulation value.” 3M Glass Bubbles
Bubble technology Hollow Glass Bubble technology was first developed by 3M in the 1960s, and has since found applications in a number of industries, from water-resistant paint to bowling balls. The microscopic glass spheres are high-strength, lightweight additives used for density reduction, thermal insulation and buoyancy in many kinds of syntactic foam compositions. They are supplied as a powder and can be incorporated into a number of polymer matrices – including as wax, polyurethane, epoxy, and silicone and others – which are then applied to oil and gas flowlines and equipment. The particles are also virtually insoluble in water leading to a number of novel subsea applications. On drill string risers, for example, glass bubble buoyancy modules prevent the steel casing from collapsing under its own weight at depth, and protect the drill string against ocean currents. 3M supplies at pressure ratings from 250 psi to 28,000 psi, and densities ranging from 0.125 grams per cubic centimetre to 0.6 g/cc. Wet insulation syntactic foam coatings made with 3M Glass Bubbles on Steel Caternary Risers (SCRs), Top-Tensioned Risers (TTRs) and riser towers have achieved overall heat
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Left: 3M Oil and Gas UK Technical Sales Manager, Darren Hall Right: A cutaway of the Glass Bubble microsphere
transfer co-efficient (OHTC or U-values) of 2 W/m² K and below. Because this construction reduces overall pipeline diameter, more pipe can be wound per spool, requiring fewer and smaller ships – installation is faster, easier and more economical. These advantages mean wet pipe insulation now accounts for the majority of all new deep water subsea flowlines. Ultimately, 3M Glass Bubbles help improve reliability and reduce costs in a variety of applications, including underwater pipelines, risers, buoys, ROVs, moorings and other deepwater components. Going deeper “The greatest challenge at the moment is to produce things which will survive in very high temperatures, wet and at an awful lot of pressure,” Hall says. “You’re looking at about 2175psi or 150 bar at 1,500m of depth, with oil coming out of the ground at 150°C which is too high for many systems.” Under the first iterations of 3M’s foams, riser buoyancy modules and wet pipe flowline insulation were capable of surviving at around to 5,000 feet (1,500 m). Today, improvements in manufacturing and the
strength/density ratio of 3M Glass Bubbles have taken this to 10,000 feet (3,050 m), with crush resistance at 15,000 feet (4,600 m) tantalisingly close. “As time has gone on we have increased our techniques manufacturing processes and what we can produce. For example, five years ago the best products we could have at 3,000-psi crush strength resistance at a density of 0.35, now we do that same strength at 0.23,” Hall enthuses. This is a 50% improvement. The firm’s newest products appeal to both extremes of the operator spectrum. 3M Glass Bubbles S42XHS are extra high-strength bubbles that can be deployed to higher pressure ratings, while Glass Bubbles XLD 3000 are extra low-density bubbles that offer significantly less weight for better thermal conductivity at a known depth rating. Hall also draws attention to some of the new applications within oil and gas which have also surfaced in recent years. Glass Bubbles have proven exceptionally useful in subsea buoyancy systems for installations, in partnership with subsea engineers such as Aubin Group. Additionally, he enthuses as to their potential for use in composites. “Composites are one of the key focuses
for oil and gas right now, to replace materials which basically rust once you put them in the sea. Anything you can replace with a composite structure is certainly of interest, and glass bubbles can help those composites become lighter,” he explains. “It takes less energy to move them around – for example a composite flowline, rather than a steel flowline requires less buoyancy – so that’s a win-win for applicators.” New frontiers UK-based 3M Oil and Gas now supplies globally, but with a particular focus on the deepwater frontiers of West Africa and Brazil. Hall notes that “offshore Indonesia is now looking good for us as well.” The company recently opened a Customer Innovation Centre in Bracknell to showcase the broad spectrum of 3M products and services, as well as and an Oil & Gas-specific Customer Engagement Centre in Aberdeen. Any interested readers can request a visit through the website below.. n Contact: 3M Oil and Gas UK Tel: +44 (0)845 607 6648 Email: oilgasuk@mmm.com Web: www.3moilandgas.co.uk/contact
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Terminal viscosity
April 2015
Researchers at Rice University have developed a method to detect and measure asphaltene in crude oil, with the aim of maintaining better production in wells and flow lines
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sphaltenes are a subset of hydrocarbon molecules found in crude oils, which as their names suggest, can be refined into bitumen or asphalt products. Highly viscous, asphaltenes are found in higher quantities in heavier, low-API crudes. However, in wells and flowlines, asphaltenes can settle or be deposited as crudes rise and change in temperature pressure and composition. This settlement can clog pipes, pumps and valves, meaning operators have either to prevent their formation via dispersants or solvents, or remove the deposits. The now-common process of CO2 enhanced oil recovery (EOR) can, in some cases, lead to changes in reservoir composition. As a result, asphaltene molecules which may previously have remained stable and intact during production are now becoming more problematic. Indeed, as fields mature and recovery factors increase, this issue is becoming more and more prevalent. In particular, asphaltenes are one of the main causes of fouling in heat exchangers during the crude distillation process. As micelles break down, asphaltenes can agglomerate and stick to the sides of the vessel wall. Indirect detection Rice assistant professor of chemical and biomolecular engineering Francisco Vargas led the study, which was recently published in Energy and Fuels, an American Chemical Society journal. The research has also been supported by the R&D Oil Subcommittee of Abu Dhabi National Oil Company (ADNOC). “Our ultimate objective is to assure the continuous production of oil,” Vargas said. “If those wellbores get clogged, regardless of what the problem is, the oil cannot flow.” So far, the industry has relied on nearinfrared spectroscopy and microscopy methods to detect asphaltene precipitation under high-temperature, high-pressure (HPHT) conditions, but neither can sense particles smaller than half a micron, so they are somewhat limited in their application, Vargas noted.
Authors of a new paper in Energy and Fuels are, from left, front: Sarah Correa, Marty Grimes and Caitlin Garcia; and rear, Mohammad Tavakoli, Quinton Cox, Xiaoyu Liu and Francisco Vargas. (Photo by Jeff Fitlow/Rice University) The experiments have led the development of “an indirect method that combines gravimetric (centrifugation) and spectroscopic techniques.” In the laboratory, this method detects and measures asphaltene – ranging from very low to very high contents in pure crude and model oils – and detects smaller asphaltene particles than can be sensed with existing industrystandard direct methods. The Rice lab’s method detects the presence of particles as small as 100 nanometres using the same near-infrared instrument currently used by industry.
The method Rather than look at the sum of asphaltene in two types of oil they studied – Middle East crude and model oil created in the lab – the Rice team used a centrifuge to remove asphaltene particles larger than 100 nanometres. This allowed them to measure the optical density of the remaining liquid to detect the precipitation of asphaltene and quantify it. By adding various amounts of heptane – which prompts precipitation – and/ or toluene – a solvent that dissolves and stabilises asphaltene aggregates – the Rice
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Asphaltenes (in black) clump together in a model oil created for testing in a Rice University lab. researchers controlled the suspension of the remaining small particles in their samples. Under a spectrometer, the absorbance of the model-oil liquid itself is near zero, so any measurement of absorbed light must be a result of the presence of asphaltene particles smaller than 100 nanometres. Light absorbance differs for crude oil because even after centrifugation, maltene, an asphalt residue, clouds the picture. But Vargas explained that a simple calibration allows for that and returns accurate results for the asphaltene particles that remain. He noted the indirect method also accounts for the presence of water in oil, while direct methods do not. While other research has detected particles as small as 2.5 to 6 nanometres – termed nano-aggregates – at this size the particles tend to remain stable and do not form problematic deposits. “As far as we know, this is the only method that can simultaneously detect the onset of precipitation and quantify the amount of asphaltene precipitated,” Vargas said. Future work – led by Rice postdoctoral research associate Mohammad Tavakkoli – will now test the method on oil samples under the same pressures as production lines, as well as potential production impairment caused by asphaltene deposition in reservoirs. n For more information, see www.news.rice. edu/2015/02/23/asphaltene-analysistakes-a-giant-step
Kongsberg’s compact camera
K
ongsberg Maritime Camera Group has designed, manufactured and delivered a new underwater video camera for use on an advanced subsea Remote Pipeline Repair System (RPRS). The cameras are specifically designed to monitor the welding arc and welding pass in an unmanned hyperbaric welding habitat, when operating to depths of 1,500 msw. An extremely wide dynamic range (WDR) image sensor is used, which provides the RPRS operating team realtime close-up viewing of the welding process while at the same time allowing detail of the adjacent welding pass to be seen with minimal image and visual
degradation from the intensity of the welding arc. The camera’s pressure housing is constructed from titanium alloy, and a sapphire front port protects the lens from damage. As space is limited in the vicinity of the weld, the camera was designed to be as compact as possible, measuring just 105mm in length and 56mm in diameter. Kongsberg Maritime Camera Group systems & projects sales engineer, Martin Tanner, commented: “We are very proud to work on this unique project and are satisfied that the final product we delivered is of the highest quality. This project was the perfect platform for our design team to showcase their capability and they did not disappoint.” n
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April 2015 Barchfeld Convention Photography
OTC looks for The Next Big Thing With the Offshore Technology Conference 2015 just around the corner, a brand new follow-up event – d5 – looks to bring together creative and innovative minds to address the industry’s biggest challenges
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s the first week of May approaches, one of the biggest events in the industry calendar – Offshore Technology Conference (OTC) – is once again just around the corner. May 4-7, 2015 will see over 90,000 delegates from more than 120 countries descend on Houston’s NRG Park for technical sessions, networking and a wealth of new kit on offer. With the year well under way, OTC always offers an excellent opportunity to take the pulse of the sector. For its part, NewsBase will be on the lookout for trends identified by the industry’s major players, including notable innovations and technological breakthroughs, as well as looking at any new or developing issues of concern, such as new safety legislations and changes in cost. This year in particular it will be important to look at how offshore players are coping with the low oil price environment. While the long lead times on offshore projects mean that investment is expected to continue offshore in the longer term, there may be some near-term challenges to contend with. OTC 2015 will see both deepwater and shallow-water challenges and opportunities discussed, and NewsBase will be following the major developments in both. In addition, the sessions will look at a number of case studies in both mature
regions and frontier offshore areas. With a particular focus on North America, NewsBase will be out on the lookout for developments in the Gulf of Mexico and offshore Canadian operations. We will also be following discussions of areas that could emerge as offshore production regions in the future, including the US Arctic and the East Coast. It will also be particularly interesting to hear from major players about their plans for Lower Tertiary development in the US Gulf of Mexico, as well as some of the latest developments in pre-salt. With production in such regions innately tied to recent advances in offshore technology, it will be areas like these which will demand some of the sector’s biggest innovations in the near future. d5 In addition to the usual programme of speakers, this year’s OTC will see the launch of a brand new follow-on event focused on innovation, creativity and ideas. Held at the University of Houston on May 8, d5 is pitched to be “unlike any other offshore energy industry event,” and seeks to bring creative minds from inside and outside of the industry to offer a fresh perspective on some of the sector’s biggest challenges. Themed “The Next Big Thing,” a number of motivational speakers and group discussions will spur creativity in
order to help identify the next big step for the offshore industry, including technology game-changers, leadership practices and competitive advantages. Among the prestigious line-up are: Jane McGonigal, a leading speaker on the engagement economy and the application of game-design to the real world; former Commander of the Naval war ship USS Benfold, Mike Abrashoff; former NASA astronaut and ex-officio member of the Columbia Accident Investigation Board Michael Bloomfield, and author, entrepreneur and consultant Frans Johansson, who has written books about business strategies and how great ideas happen. OTC will host a preview webcast to formally introduce the inaugural d5 event and inform potential attendees about the conference on Tuesday, March 31 at 10 a.m. (CDT). Hosted by d5 advisory board and committee leaders including Helge Hove Haldorsen, Steve Balint and Art Schroeder, the webcast will be open to the public and will include brief presentations as well as a Q&A session. “Technology is changing so fast outside of our industry,” adds d5 Programme Committee chairman Schroeder. “We’re trying to get some of that speed injected into our industry.” n For more information about OTC, please visit: www.otcnet.org
Third-party HIL testing Modern ships and rigs have advanced computer systems for dynamic positioning, power generation & distribution and drilling operations. Software errors in these systems lead to delay, non-productive time and compromise safety. Marine Cybernetics performs third party software. We detect and eliminate such errors and weaknesses using Hardware-In-the-Loop (HIL) testing technology.
• Reducing incidents and accidents • Reducing off-hire and non-productive time • Securing safe and reliable operations Meet us at the Offshore Technology Conference in Houston May 4-7, booth #5129 in the Norwegian Pavilion
safe software – safe operations
MarineCyb-contact@dnvgl.com | marinecyb.com
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All riser with Aquaterra
Aquaterra’s Riser Monitoring System (RMS) offers a unique, robust method to provide real-time information on riser operation
R
isers are, naturally, one of the centrepieces of any offshore oil and gas installation. But they are also subject to some of the harshest conditions, including ocean currents, wave loads and more general fatigue over the producing life of the project. Monitoring the integrity and performance of the riser stack is therefore vital to ensuring safety and flow, as well as minimising risk. With the impact of riser damage having significant cost implications, it is important to know when to plan maintenance and/or replacement, maintain production efficiency and extend asset life. With such a widespread industry focus on riser integrity and fatigue, Aquaterra Energy has developed the unique Riser Monitoring System, or RMS. The system uses a combination of direct riser strain measurement, subsea data-logging and processing algorithms to generate accurate, real-time information for drilling and workover operations in water depths of up to 100m. Taking the strain The RMS is a bespoke, standard-length riser joint, which replaces a standard riser joint in the stack up, with pre-installed data acquisition and logging hardware.
Four robust strain gauges directly attached to the riser ensure the fidelity of direct strain measurements, rather than measurements which may be corrupted by the flex or movement of a clamped attachment, as in other solutions. By attaching these gauges to the riser with subsea epoxy resin, the RMS does not require welding and avoids damaging any existing fatigue on weld spots. The entire instrumentation is then covered with a heavy-duty housing for full impact protection. The result is accurate data-logging and monitoring with virtually no impact on operation. Indeed, by pre-installing the system on the riser before the stack is built, users will experience almost no interruption to the operation. The RMS can store data locally, or instantly transmit the data to the surface for live evaluation, processing and reporting. The logger records all pertinent information at a rate of 10Hz, and can store up to 560 days of continuous data in its 32 GB memory card. Although powered from the surface, an on-board battery pack will supply the RMS for 250 days of use. The option of additional battery packs means the system can be installed for anything from short operations right up to 5 years of continuous service. All hardware is
ATEX Ex ib IIB T4-certified for subsea or surface and fully compliant with DNVRP-F206 and ISO 13628-7 specifications. Computing power Prior to the RMS being run, an intensive riser analysis programme takes place, which produces results which, when combined with the data from the RMS, allow the fatigue damage along the length of the riser to be extrapolated from a single measurement point. The information obtained from the RMS provides the stress range, period and directionality at the RMS location and is then combined with the Aquaterra pre-processed data to determine the fatigue damage along the length of the riser. This ensures that the determination of the fatigue damage – including the usually time-intensive component fatigue calculation – is rapid. Aquaterra Energy regional director for Europe, Eric Doyle, comments: “The RMS gives a greater understanding of the true fatigue life of a Riser. This greater understanding can extend operations, save time and money.” n Contact: Stuart McIntosh Tel: +44 (0)1224 651 250 Email: stuartmcintosh@aquaterraenergy.com Web: www.aquaterraenergy.com
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COMMENTARY
Showcasing innovation at ITF The ITF Technology Showcase explored the exciting potential of inter-industry collaboration, as well as the announcement of £11 million of UK funding for new innovation
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he Industry Technology Facilitator’s (ITF) Technology Showcase is only in its second year, but via events like this it has proved willing to push the industry in new and innovative directions. With ITF CEO Paddy O’Brien calling for “collaboration at every level,” the conference explored how new innovations could bridge the gap between concept and market. Bringing SMEs and new technology providers together with prominent figures from international oil and gas operators and industry bodies, ITF hopes to foster better collaboration, while delegates can very much get a feel for where the industry stands – in the boardroom and on the technology front line. In particular, the Showcase drew attention to the knowledge and practices which could be gained from similar UK industries, inviting presentations and delegates from the automotive, aerospace, defence, nuclear and materials sector. These formed a centrepiece to the event, highlighting the strategies these industries had used to collaborate, channel innovation and – crucially to many in the room – how to approach the funding to make new R&D feasible and competitive. Plenary The conference’s first session offered some strategic updates and technology priorities. Oil and Gas UK operations director Oonagh Werngren explained that while two of OGUK’s three aims were being addressed – the award of tax cuts and investment allowances for new exploration, and being given the robust regulator in the form of the nascent UK Oil and Gas Authority (OGA) – it was still working extensively with industry to address the core issues of cost and efficiency. On the sidelines of the conference, InnovOil asked Werngren whether the words of the Wood Review were being heeded by industry. “I think they are,” she affirmed. “I think there’s probably a long
way to go, but I think the initiation of the OGA will really put everybody to the test.” Lloyd’s Register energy director John Wishart built on this conclusion, highlighting some of the findings of Lloyd’s Technology Report from 2014. This was encouraging – respondents voted safety as their number one priority – but cost was a close second across the board. But the industry’s requirements for technology and innovation varied by region; the UK wanted more freedom in terms of R&D and robust supply chain; Singaporean meetings showed NOCs now wanted to be seen as technology innovators, rather than buyers; in Houston, commercialisation and bringing products to market was key. Lloyd’s Abu Dhabi forum suggested that the Middle East now wants to explore the crossover potential of other industries, harnessing breakthroughs in medical science, aerospace and new IT capability from Silicon Valley and applying them to oil and gas. Fortunately, this possibility was explored in the showcase’s next session. But this is not to say that rival sectors will offer silver bullet solutions. As Total E&P UK managing director Philippe Guys remarked, low prices and harder-to-reach resources mean that “risk-taking is all the more important.”
ITF chief executive Dr Patrick O’Brien
Transfer window The centrepiece of the conference saw Paddy O’Brien welcome leading figures from other industries to the stage, with the aim of discovering what technology, collaboration and funding models could be transferred to the oil and gas sector. Nissan UK’s general manager for innovation and performance products, Jerry Hardcastle, put forth a vision of the UK automotive industry several years ago that was not dissimilar to oil and gas now: despite engineering talent and company capital, the sector was struggling to make money, a situation exacerbated by the 2008 recession. The UK government’s demand for the industry to spend its money more effectively was a valuable incentive – and a wake-up call. In response, several manufacturers submitted their visions of the automotive future to a third-party consultant in the hope of finding some common ground. The result was that, despite working in insolation, all saw the electrification of drive trains as their priority for the next decade. So the Automotive Council was established, along with the UK Automotive Technology Strategy, which set a roadmap for the whole UK industry. The moral of the story, according to Hardcastle, is that companies should not
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COMMENTARY From left: Total E&P UK managing director Philippe Guys, National Composites Centre technology director Professor Mike Hinton, Lockheed Martin head of information management Neal Stidolph and the Aerospace Technology Institute’s chief operating officer Ruth Mallors-Ray
other resources required to take innovative ideas from concept to reality.” These aim to bridge the vital gap between the midlevel TRLs, taking innovations which are lab-proven and bringing them to an early commercial stage. Catapult research is co-ordinated at seven leading UK facilities, including a high-value manufacturing division, one in offshore renewables and a new energy forum.
collaborate on the later stages of Technology Readiness Levels (TRLs), but instead work together as early as possible to carry the whole industry forward. Rather than competing for the smallest advantages, collaboration on the fundamentals hedges risk, and provides valuable ROI to all firms involved – a model from which oil and gas firms could learn. Aerospace Technology Institute COO Ruth Mallors-Ray noted a similar approach for the UK’s aerospace industry. In a situation not dissimilar to that of the UK subsea industry, she pointed out that the UK was the primary country for aerospace manufacturing in Europe – contributing £24 billion to the economy – but that this position should not result in complacency. Much as in oil and gas, R&D spending in aerospace is a business decision, but as Chinese and Brazilian firms catch up in terms of manufacturing and engineering capability, UK companies must co-operate at some level if they are to stay ahead of the curve. This recognition led to the formation of the Aerospace Growth Partnership in 2010 and the UK Aerospace Technology Institute in 2013, focused on encouraging the industry to develop the next generation of aircraft, and to make sure this was done in the UK.
Fundamentally, this technology strategy had to be market-led, again ensuring that companies and investors were given a return on their investment. This strategy would also provide a focus for the technologies on which companies could collaborate effectively. The global presence of oil and gas companies, the longer cycles of return on technology investment, the high focus on safety and the skills and employment they need are all analogous to those of aerospace, she added. A similar strategy of technology development and co-operation would be an excellent model for the oil and gas industry to follow, particularly under the new guidance of the OGA. Fortunately, the industry is already listening. Oil and Gas Innovation Centre (OGIC) chief executive Ian Phillips drew attention to the centre’s work on linking academic research facilities with industry technology and innovation. Having been formally launched in November, OGIC has already had 75 companies approach them for assistance, 18 of which are in extended discussions, and two of which have signed development agreements. He also highlighted the potential of the Catapult project, which offers interindustry collaboration via “access to expert technical capabilities, equipment, and
Funding innovation Meanwhile, for the struggling inventors and nascent start-ups, the showcase also offered the opportunity for new funding packages made available through Innovate UK, a unit of the Department for Business Innovation and Skills. A total of £6 million is available to support new technologies that “improve efficiency, reduce cost and minimise the environmental impact of coal, natural gas and oil.” £4 million of this will be allocated for collaborative, industry-relevant R&D projects ranging in size from £250,000 to £1.5 million, and £1 million for small-scale feasibility studies. Meanwhile, the National Environment Research Council (NERC) is also providing £1 million for academic projects which meet these requirements. In a separate initiative, a further £5 million is available over five years as part of NERC’s Oil and Gas Innovation Programme, which has a particular focus on decommissioning. Innovate UK lead technologist for energy Derek Allen commented: “We are actively seeking innovations…which could be anything from advanced fossil fuel process technologies to carbon capture and storage [CCS] or new approaches to decommissioning. We anticipate interest from the oil and gas sector as well as power generation and energy-intensive industries.” The deadline for expressions of interest for collaborative R&D – for which there is a two-stage process – is noon on April 15, 2015, while feasibility studies must be submitted by noon on June 10, 2015. Innovators: start your engines. n
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Seamless supply Castrol’s technical services manager, Tony Globe, explains how global standardisation for products and services within the offshore market can save time and money
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he need for mobile offshore drilling units (MODUs) to relocate poses a constant challenge to safe, seamless operations. Without a global product and service supply agreement, operators must use multiple suppliers in their enterprise resource planning (ERP) system. However, the complexity of managing numerous stock-keeping units (SKUs) increases administration costs and affects the ability to leverage buying power. This is a particular issue for operators which view each asset – or grouped regional assets – as autonomous units which make their own buying decisions. Instead, some offshore drilling majors are now looking to achieve supply continuity of quality components through global standardisation. Global suppliers such as Castrol offer a product portfolio aligned with the overwhelming majority of fleet applications and that is available in vital locations. One component for which this approach is particularly beneficial is lubricants – an essential tool in ensuring engine maintenance and preventing malfunction. In the international drilling market, global standardisation is particularly advantageous, as it eliminates the need to switch suppliers and lubricants when the rig moves to a new location. Multiple applications MODUs require lubricants for all key applications, including drilling, power generation, handling systems (e.g. pipe & casing manipulation), the dynamic positioning and motion compensation systems on floating units, elevating systems for jack-ups and safety systems. All this must be done, even before the subcomponents, like gearboxes,
compressors and hydraulic systems are included. Faced with so many key applications, as well as the need to protect infrastructure in harsh environments while obeying stringent environmental legislation such as OSPAR, operators are using hundreds of individual lubricants to fulfil the safety, operational and regulatory demands of their MODU fleet.
A global product and service supply agreement can negate these issues by enabling the standardisation and rationalisation of vendors on the system, encouraging automation and saving costs. Wherever possible, products are rationalised across the asset base and unnecessary SKUs can be removed to simplify supply. One customer was able to reduce complexity by product consolidation from around 300 down to approximately 50. Castrol works closely with asset owners,
designers, construction facilities and equipment manufacturers to ensure that the lubricants we recommend are appropriate for the application. Meanwhile, using environmentally responsible lubricants such as its Bio Range as standards means operators can avoid disruption when moving MODUs between different regulatory regimes. Understanding performance Looking at fleet performance from a global perspective can also identify where gains can be made. Using a condition monitoring system such as Castrol LabCheck, operators can see performance and identify any risks of malfunction. For example, in the case of lubricants, if there are more than 100 identical engines running on a certain oil, but three rigs are having to change lubricant before the others, it is possible to investigate what is causing more rapid degradation. Ultimately, larger companies are becoming more sophisticated. They want transparency in terms of how well operations are functioning and to be able to understand appropriate lubricant life. The core objective of any driller is to be able to access the right product, at the right time, in the right quantity in order to continue to operate. This is why harnessing global standardisation to maintain supply continuity is critical; without it, a variety of different products makes it hard to conduct meaningful analysis and understand performance. n Contact:
Tony Globe, Global Technical Services Manager & Technical Authority Tel: +44 (0)7785 705 703 Email: tony.globe@castrol.com Web: www.castrol.com/globalbusiness
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Flying April 2015
The AgustaWestland AW609 TiltRotor can fly at twice the speed and range of a helicopter. Could this be the future of offshore transport?
InnovOil
Full-Tilt April 2015
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M
arch 3 saw Anglo-Italian aviation firm AgustaWestland announce the start of production on its latest, gamechanging aircraft. The firm’s Philadelphia manufacturing facility is gearing up to support the first final assembly line of the AW609 TiltRotor – an aircraft capable of vertical take-off and landing (VTOL), but with the flight range and speed of a fixed-wing – in anticipation of civil certification from the US Federal Aviation Administration (FAA) in 2017. The announcement also coincided with the signing of a new platform development agreement for the TiltRotor programme between AgustaWestland and offshore transport service provider Bristow Group. A Bristow spokesperson told InnovOil that this “sets a working team in motion to develop [the aircraft’s] potential capabilities.” But more than this, the agreement and the implications of the TiltRotor for the offshore market, “mark a significant step towards the production of an aircraft type that will provide an ideal transportation solution for offshore travel in the future.”
AgustaWestland test pilot, Paul Edwards
Into the wild Harsher operating environments for hydrocarbon production have necessitated a wealth of innovations, but the method of getting crews from point A to point B has remained mostly the same. While, in general, onshore environments pose fewer problems, offshore crew transport is usually undertaken by boat or by helicopter – more often than not, the latter. The result is that, aside from minor incremental improvements, offshore operators and civil helicopter transport providers use a relatively fixed number of similar models for crew changes. These are chosen primarily by their ability to balance the distance needed for the mission (often long offshore trips) with the number of passengers on board. For example, the Eurocopter EC225 – used by a number of NOCs, service companies and helicopter operators – carries up to 19 passengers and has a maximum range of around 450 nautical miles (nmi). Similar models such as the Sikorsky S-92 will carry 19 passengers,
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but 50 nmi further, while the smaller-still AgustaWestland AW139 carries fewer passengers (15), at a longer range of around 560 nmi. As such, these options form part of the backbone of offshore transport. But as drilling moves further and further offshore and into previously inaccessible locations onshore, the requirements of new frontiers push at both the potential for crew carrying and aircraft range. At around 200 miles offshore, Shell’s Perdido platform is one of the farthest out in the Gulf of Mexico. A typical round trip in a long-range S-92 will take between 3 and 4 hours – or 24 hours by boat – to ferry a typical crew back and forth on 14-day shift rotas. Even carrying 22 passengers each, that is a lot of journey time and a lot of fuel, all of which will is reflected in lifting costs. At ranges of 200 and 300 nmi, especially in operations around Australia or Nigeria for example, helicopter transport hits a technological wall. Without a network of re-fuelling stops for ranges above, choppers cannot transfer personnel in one trip, opening a window of necessity as explorers push into deeper, remoter waters. As the industry looks to raise its efficiency at a lower cost, the conventional set-up of helicopter transport is a prime target for some much-needed innovation. Better weather forecasting may allow us to predict flight conditions more accurately and better production efficiency measures mean that rig crews can work better when offshore – but they still need to get there. Rotary revolution One such innovation comes in the form of AgustaWestland’s TiltRotor. Unique in terms of civil aircraft, the AW609 combines the benefits of both a helicopter and a fixedwing aircraft. Its versatility and its economic implications make it an attractive proposal, while the all-important VTOL capability and mean it can be deployed to almost any existing helicopter infrastructure. “The aviation world is divided between fixed wing and helicopters. If you want to take off from a runway, fly 2,000 miles and land on a runway, you’d take a 777,” AgustaWestland test pilot, Paul Edwards, explains. “But if you haven’t got a runway you have to use a helicopter, and helicopters
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The AW609 demonstrating vertical take-off and landing
are limited by the advancing blade problem: if you spin a main rotor, then the blade going forwards adds the speed of rotation to the aircraft speed and very soon you’re into supersonic effects. This tends to limit a helicopter to a maximum speed of around 160 knots.” You cannot change the laws of physics, as the saying goes. By far the greatest benefit of the 609 is that it can fly at nearly twice the speed and twice the range of a typical helicopter. Carrying up to nine passengers – in addition to the two flight crew – the TiltRotor could dramatically reduce the cost of long-range crew transfer. The 609’s 275-knot top speed is unmatched by conventional helicopters. “If we can fly for 2 and half hours, we can go at in excess of 250-270 knots and travel around 700 miles. All of that is something that a helicopter simply cannot do and probably never will be able to do.” What’s more, Edwards says: “We’re pressurised so we can climb way beyond what helicopters usually go to, up to about 25,000 feet [7,600m].” Being able to reach this altitude means all but the worst thunderstorms can be avoided. “In the North Sea, low cloud and icing are always problems, especially in winter – this aircraft can get above that weather and only [has] to come down when it has to land on the platform.” The TiltRotor’s flight ceiling also enables it to take advantage of tailwinds. “For instance,” Edwards comments, “We flew from Texas to Florida three weeks ago and we were travelling at over 400 miles an hour, taking account of the extra speed of the aircraft and the winds we can get if we go high enough.” Current specifications mean the 609 can cover around 500 nmi point-to-point with a full load of nine passengers in two hours. But underwing auxiliary fuel tanks are also being developed to increase range and expand possible mission profiles, taking this to around a 1,100-nmi maximum, or to fly six passengers around 800 nmi in a little over three hours. Flight tests The aircraft has been in development, in various forms, for decades. Originally, named the BA609, it was a collaborative project in the early 2000s between Agusta and Bell Helicopter, using technology from Bell Boeing’s V-22 Osprey project. Although the Osprey was eventually successfully deployed, reaching operational
status with the US Marine Corps in 2007, Bell Helicopter was unhappy with the progress and commercial opportunities of the civil BA609 variant. AgustaWestland eventually bought Bell out of the project in 2011 – though the latter remains involved as a subcontractor – and after years of delays, the AW609 is now in the first stages of commercial production. It is “a pretty easy aircraft to get on with,” Edwards says. “We’re basically flying the same aircraft that was designed 15 years ago, and that’s a good indication of how good it is. We haven’t had to change that much.” Two PT6C-67A engines deliver Cat A Class 1 performance at the 609’s maximum take-off weight (MTOW) of 7,620 kg. Using the rotors as a conventional turboprop would, the aircraft can also perform short take-off and landing (STOL), allowing an 8,165-kg MTOW for more flexibility in terms of cargo and payload, where runways are available. Inside, a full touch-screen digital glass cockpit also contains advanced navigation systems, in addition to flyby-wire technology. An in-built de-icing system means the 609 can fly in full icing conditions, effectively enabling transfer and operation anywhere in the world. The rotors also allow for another unique manoeuvre. “We can tilt the rotors backwards a little. If 90° is ‘rotors pointing upwards like a helicopter,’ we can actually tilt them to 95°.” In addition to aiding the 609 in stopping quickly, it makes landing far easier for pilots, Edwards explains. “Whereas in a helicopter – where you have to have the nose up on a descending approach, which reduces visibility – we can keep the nose tilted down, increasing the field of view.” This will help missions which require aircraft to land on small helipads, on moving rigs and ships, in wild offshore conditions.
Increased passenger comfort is also a major bonus. The lack of an overhead rotor vibrating the cabin results in a far more relaxing journey, “above all that turbulence and wind,” Edwards enthuses. “It’s like flying a 737 to a rig – that’s the kind of comfort that we’re talking about.” Ready for take-off So far, two working prototypes have logged nearly 1,200 hours of flight time, with a third prototype nearly complete at the firm’s Philadelphia facility – also the site of the first full TiltRotor assembly line. With around 60 orders in place, production is expected to ramp up in both the US and at the company’s Vergiate facility in Italy further down the line. Bristow said that it was too early to specify where the aircraft would be used, but with the company’s focus on oil and gas transport, it was likely that upstream applications would quickly develop once certified. The company’s most active regions – the North Sea, Nigeria and the US Gulf of Mexico – immediately spring to mind. While AgustaWestland is understandably tight-lipped on the price, Edwards is fairly clear on where the market lies. “I think our costs will be comparable to a helicopter, to be quite honest,” he says. “In terms of helicopters and short distance transits – certainly in terms of distances for oil and gas transport – we’re aiming to be right up there in terms of efficiency.” So is the TiltRotor the future of aviation? “It’s really going to change the whole transport experience for oil workers, I believe.” Edwards says. “If you want to fly 600 miles and one or both of your locations are a helipad, you’re going to want a TiltRotor. It will take up a big chunk in the middle of the future aviation world.” n
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April 2015
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What next …? To make enquiries about any of the products or technologies featured in this edition, use this list of vital connections If you are interested in speeding up the process of field joint coating, please contact +44 (0) 1256 335 533 or email Inductotherm Heating & Welding at info@inductothermhw.co.uk. To enquire about 3M Glass Bubbles and how they could be of benefit to your subsea infrastructure or offshore equipment, call 3M Oil and Gas UK on +44 (0) 845 607 6648 or email: oilgasuk@mmm.com If innovative riser monitoring can help you plan maintenance and protect riser integrity, contact Aquaterra’s Stuart McIntosh on +44 (0)1224 651 250 or click stuartmcintosh@aquaterraenergy.com For more information on Kongsberg Maritime’s pipe welding camera, call Kongsberg on +44 (0) 1224 226 500 If standardisation could save you money on global rig operations, contact Castrol’s Tony Globe on +44 (0)7785 705 703 or reach him at tony.globe@castrol.com If you would like to hear more about the AgustaWestland AW609 TiltRotor, please contact Geoff Russell Geoff.Russell@agustawestland.com
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InnovOil, from the NewsBase group, is a technology-driven, monthly magazine which aims Andy Hill, Group Marketing Manager to provide a platform for innovators and engineers to share to share their ideas and expertise. IPU Group Our publication remains a trusted, solicited information source for technology news across the complete spectrum of the upstream, midstream and downtream oil andwith gas the sectors. “We were pleased
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