Oil, Gas and Shipping Magazine by Oil, Gas and Shipping

ISSUE 77 www.ogsmag.com

Shell The biggest getting bigger

Providing Oil & Gas solutions for tomorrow’s needs

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The Editor

Editor

The

Martin Ashcroft

Forgive us our carbon sins “Forgive me father, for I have sinned.” “I’m sorry to hear that, my son; what have you done?” “I flew to the Far East for a meeting, father, so I am now personally responsible for the emission of 1.7 tons of carbon dioxide.” “How can you be so precise about your sin?” asks the priest, wondering how many ‘Hail Marys’ would offset a ton of carbon dioxide. “I typed ‘carbon neutral’ into Google, father, and clicked on a website with a carbon calculator. It also told me how many trees have to be planted to erase my carbon footprint.” “Did your meeting contribute in any way to the benefit of the planet?” asks the priest. “Oh, yes, father. We agreed on a policy of free trade with underdeveloped countries.” “And did the almighty carbon calculator take that into account?” “I don’t think so, father.” “So what makes you think that carbon dioxide contributes to global warming, my son?” asks the priest.

“Well, everyone knows that, don’t they, father? It’s all over the internet. All the scientists say so and all the politicians, too. So it has to be true, doesn’t it?” “In my business,” says the priest, “we call that faith, but it’s blind faith unless you understand what you believe and why.” “Can you explain that, father?” “Modern technology allows us to measure things more accurately,” explains the priest, “but that doesn’t mean we understand them any better. Carbon emissions might be easy to calculate and atone for, but do we really understand why they are supposed to be bad for the planet?” “So what should I do, father?” “Look at the evidence with an open mind, my son, and form your own opinion. Then ask your friends to do the same.” “Thank you, father, I feel much better now.” “You’re welcome, my son,” says the priest. “Offsetting sins is my job description.” Martin Ashcroft martin@ogsmag.com www.ogsmag.com

Contents Cover Story Shell: The biggest getting bigger

03 06 09 09 09 13

The Editor: Forgive us our carbon sins Monthly news and features Olive Group to merge with Constellis Group China oil demand up 6.5 percent Applus RTD successfully tests INCOTEST project News in Brief

13 13 15 15 17 19

s ly new Month res & featu

22 Puma Energy opens fuelling hub OPECâ&#x20AC;&#x2122;s April oil production Shell granted US Arctic drilling approval Agility to open new factory in N.Carolina US LNG export terminals nearing operation Yemen coast security issues

21 52 56 62 64 68

Aberdeen Harbour growth How sustainable is shale gas? A weather eye: Medium range weather forecasting Open locks: David Blond on the Panama Canal Offshore Europe 2015

Vulcan Systems

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News and features

Olive Group to merge with Constellis Group Olive Group, a leading provider of risk management solutions to blue chip commercial customers in the energy, aviation and infrastructure sectors, is to merge into the Constellis Group of companies to create a global leader in security, risk management and complex program management services. Headquartered in Reston, Virginia, Constellis Group is a family of companies providing complementary advisory, security, training and managed support services to governments, multinational corporations and international organizations worldwide. Olive Group is headquartered in the Middle East with principal offices in the United Arab Emirates, UK and US. Its co-founders Chris and David St. George will join Constellis Group’s board of directors but Olive Group’s management team will remain unchanged. The transaction furthers Constellis Group’s participation in the commercial sector and provides global expansion into established and emerging markets across several continents.

Applus RTD successfully tests INCOTEST project

China oil demand up 6.5% in March

China’s apparent oil demand* in March increased 6.5% from a year earlier to 44.73 million metric tons (an average 10.58 million barrels per day), according to Platts’ analysis of Chinese government data - the highest growth rate since September 2014. Data from the country’s National Bureau of Statistics showed China’s refinery throughput in March averaged 10.57 million b/d, rising 5.5% from a year earlier. On the other hand, net oil product imports fell to a four-month low of 40,000 mt, according to data released by the General Administration of Customs. During the first quarter of this year, China’s total apparent oil demand was up 4% year over year to an average 10.48 million b/d,

the highest pace of growth over the same three-month period since 2012. This came despite China’s GDP growth sinking to 7% for the quarter, the slowest quarterly rise in six years. *Platts calculates China’s apparent or implied oil demand on the basis of crude throughput volumes at the domestic refineries and net oil product imports, as reported by the NBS and Chinese customs. Platts also takes into account undeclared revisions in NBS historical data. The government releases data on imports, exports, domestic crude production and refinery throughput data, but does not give official data on the country’s actual oil consumption figure and oil stockpiles.

Applus RTD has successfully completed an advanced non-destructive testing project with its RTD INCOTEST technology, a unique corrosion survey method that allows ferrous objects to be surveyed without the need to make contact with the surface. Measurements can be performed on objects covered with insulation, asbestos, fire proofing, concrete or any other kind of coating. A sensor is placed on top of the insulation, then using a pulsed, low frequency magnetic field, eddy currents are generated in the material. By measuring the duration of the currents, a thickness calculation is made. The system can be used on material with a thickness of up to 65mm and on high temperature objects. www.ogsmag.com

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News and features News in Brief Floating regasification is a flexible, cost-effective way to receive and process shipments of liquefied natural gas (LNG) and is increasingly being used to meet natural gas demand in smaller markets, or as a temporary solution. The US Energy Information Administration reports that of four countries planning to begin importing LNG in 2015, three of them—Pakistan, Jordan, and Egypt—have chosen to do so using floating regasification rather than building full-scale onshore regasification facilities.

Puma Energy opens strategic CBM fuelling hub in Angola

* * * Aberdeen–based international energy logistics provider Peterson, together with its software subsidiary Streamba, has unveiled VOR, an interactive upstream oil and gas procurement and logistics service. Customers, vendors and suppliers can enter data relevant to their supply chain operations and VOR provides a real-time view of where the goods or services are at any time, from warehouses and vessels, to pallets, helicopters, containers and trucks. * * * Flexlife has won a subsea project management and engineering support contract with oil and gas exploration and production company Apache North Sea Limited. The three year contract includes work on the Aviat gas development in the Central North Sea, the Ness/Nevis tie in and general subsea operations support. Flexlife has a six-year history of project delivery with Apache North Sea Limited on projects including the Bacchus subsea development and a major subsea isolation valve project on Forties. * * * UK-based Global Marine Systems Limited, a specialist in subsea cable engineering projects, has landed a pair of high-profile contracts from Tampnet, whch operates the largest offshore high-capacity communication network in the world in the North Sea and the Gulf of Mexico.

Puma Energy, the globally integrated midstream and downstream energy company, has opened one of the world’s largest conventional buoy mooring systems in Luanda Bay, Angola. The fuel loading buoy anchored offshore serves as a strategic mooring point for Africa and it will allow a wide range of carriers to berth while loading or offloading oil product. The new CBM is located next to Puma Energy’s Fishing Port Terminal in Luanda Bay, which is currently being extended and will have a total storage capacity of 276,000 m3. The CBM meets Oil Companies International Marine Forum (OCIMF) standards and can

accommodate vessels up to 225,000 dead weight tons (DWT) with a draft restriction of 19.3m. It has bi-directional flow and a nominal product transfer rate of 4,000 m3 per hour on both lines. “We constantly assess new and strategic infrastructure investment opportunities which help us provide safe, reliable and cost effective supply, storage and distribution solutions to our customers,” said Pierre Eladari, CEO for Puma Energy. “This new CBM facility in Luanda provides security of supply to and from Angola as well as Africa.” Improved efficiency at the Port of Luanda will help Angola’s economy to remain amongst the fastest growing in Africa.

Oil production from OPEC totaled 30.93 million barrels per day (b/d) in April, up 210,000 b/d from March, according to the latest Platts survey. The April total is the highest since November 2012, almost one million b/d above the 30 million b/d ceiling set in 2012. The biggest single increase in April came predictably from Saudi Arabia itself, which increased output by 100,000 b/d to 10.1 million b/d. Smaller increases came from Iran, Iraq, Kuwait, Libya and Nigeria. Saudi oil minister Ali Naimi said last month that the kingdom was willing to help restore stability to world oil markets, but only if major non-OPEC producers were also ready to participate. www.ogsmag.com

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News and features

Shell granted conditional US Arctic drilling approval Royal Dutch Shell has been given approval to explore for oil in the Arctic by The Bureau of Ocean Energy Management (BOEM), an agency of the US Department of Interior, subject to the necessary approvals being granted by other interested authorities and regulatory bodies. This is an important step for the company and a sign that the authorities believe its current plans and safety procedures have improved since 2012 when it suspended operations after an oil rig fire and other safety issues. “We have taken a thoughtful approach to carefully considering potential exploration in the Chukchi Sea, recognizing the significant

Agility to open new factory in North Carolina

environmental, social and ecological resources in the region and establishing high standards for the protection of this critical ecosystem,” said BOEM Director Abigail Ross Hopper. “As we move forward, any offshore exploratory activities will continue to be subject to rigorous safety standards.” The Arctic is said to have about 20% of the world’s undiscovered oil and gas, and Shell has already invested around $6 billion (£3.85 billion) on exploration in the region. Shell’s revised exploration plan proposes the drilling of up to six wells within the Burger Prospect, in approximately 140 feet of water about 70 miles northwest of the village of

Wainwright, using the drillship Noble Discoverer and the semi-submersible drilling unit Transocean Polar Pioneer, with each vessel providing relief-well capability for the other. A spokesman for Shell said the approval was an “important milestone” that “signals the confidence regulators have in our plan”. “However, before operations can begin this summer, it’s imperative that the remainder of our permits be practical, and delivered in a timely manner. In the meantime, we will continue to test and prepare our contractors, assets and contingency plans against the high bar stakeholders and regulators expect of an Arctic operator.”

Agility Fuel Systems, designer and producer of natural gas fuel storage and delivery systems for heavy duty trucks and buses, is to open a 204,000 square foot production facility in Salisbury, North Carolina, strategically located north of Charlotte, close to heavy duty truck and bus OEM assembly plants. The company claims the new factory will be the industry’s first vertically integrated natural gas fuel system production facility, and will include in-house manufacture of light, high-capacity CNG cylinders, the latest production technology and an in-house state of the art paint line. The plant is designed for maximum flexibility and will include multiple flowthrough bays to maximize installation efficiency, with fueling capability onsite for both CNG and LNG. “Our new vertically integrated facility will enable improved logistics, guaranteed cylinder capacity to our customers, the highest standards of quality expected by OEMs, rapid product innovation and speed to market,” said President and CEO Barry Engle. “Agility’s investment in this facility demonstrates our deep commitment to the development and adoption of natural gas as a transportation fuel in the heavy duty vehicle industry.” www.ogsmag.com

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News and features

US LNG export terminals nearing commercial operations Cheniere Energy’s Corpus Christi, Texas, liquefaction export facility, approved by the Federal Energy Regulatory Commission (FERC) last December, is moving toward construction with an anticipated start-date during the second quarter of 2015. If this goes ahead as planned there will be five liquefied natural gas (LNG) export facilities in varying stages of construction in the 48 states of the continental US. Four of these LNG terminals are brownfield projects being developed on existing regasification sites already in operation, which allows them to share functions with existing LNG import facilities to conserve on construction and operating expenses. Cheniere’s Corpus Christi facility, being developed on Cheniere’s La Quinta Channel property previously approved for a regasification facility (but not constructed), is the first greenfield project approved by FERC. These East Coast and Gulf Coast facilities, representing nearly 9 billion cubic feet per day (Bcf/d) of

LNG export capacity, are expected to begin operations in late 2015. All of them are scheduled to be in service by 2018. The first US LNG export facility to file for FERC approval was Sabine Pass in Louisiana. This four-train facility is approved to export 2.2 Bcf/d, and is scheduled to enter service by late 2015, with full capacity projected to be online in 2016. Cameron LNG in Louisiana is slated to be a three-train LNG export terminal that will be capable of exporting 1.7 Bcf/d of LNG, much of which is contracted to its partners. Construction on this project began in October 2014, with commercial operation expected to begin in 2018. The Cove Point facility in Maryland began LNG import operations nearly 40 years ago, but the marine terminal has been mothballed for much of the time since then. The cryogenic tanks have been used for storage, however. The export project, which will add a single 0.82-Bcf/d train, is targeted to begin operations in late

2017. Construction of the off-site facilities supporting this project began in late October 2014. The Freeport LNG and Corpus Christi LNG terminals, both in Texas, have respective capacities of 1.8 Bcf/d and 2.14 Bcf/d. Freeport LNG began construction of its three-train facility in November 2014, while construction of the Corpus Christi three-train LNG export terminal, which will include construction and operation of a 23-mile long, 48-inch diameter, bidirectional pipeline, is expected to start soon. Both facilities are scheduled for commercial service in 2018. Even before operations begin, expansions are in the works for Sabine Pass and Cameron. Both asked FERC for two additional LNG liquefaction trains. The Sabine Pass expansion, approved by FERC on April 6, will add additional capacity of 1.3 Bcf/d, while the Cameron LNG expansion will add 1.4 Bcf/d of capacity, if approved. Published in association with the US Energy Information Administration www.ogsmag.com

News and features

Growth in oil trade off Yemen coast threatened by security issues

Oil trade off the Yemen coast grew by 20% to 4.7 million barrels per day in 2014. While Yemen is not a major oil-producing country itself, its coast borders the Bab elMandeb Strait, a narrow chokepoint between the Horn of Africa and the Middle East. This strait is a strategic route for Persian Gulf oil, natural gas, and petroleum product shipments to Europe and North America, as well as European and North African oil exports to Asia. Although the strait is 18 miles wide at its narrowest point, tankers must use two 2-milewide shipping channels. Trade in crude oil and petroleum products transiting the Bab elMandeb has increased in recent years, growing from 2.7 million barrels per day in 2010 to almost 4.7 million bbl/d in 2014. From 2013 to 2014, trade grew by more

than 20%, with an increase of more than 200,000 bbl/d in crude oil exports from Iraq to Europe contributing to higher northbound traffic. Record-level exports of crude oil and petroleum products (particularly distillate fuel oil) from Russia to Asia contributed the most to higher southbound traffic through the strait, somewhat offset by declines in exports of petroleum products from Europe and exports of crude oil from Libya. About 30% of Bab el-Mandebâ&#x20AC;&#x2122;s southbound traffic also passed through the Suez Canal or the Suez-Mediterranean (Sumed) pipeline. There is a danger that increased instability around the Bab elMandeb could prevent tankers in the Persian Gulf from reaching the Suez Canal or the Sumed Pipeline, diverting them around the southern

tip of Africa, adding to transit time and cost. In addition, European and North African southbound oil flows may no longer be able to take the most direct route to Asian markets through the Suez Canal and then on to the Bab el-Mandeb. As the security situation in Yemen has continued to deteriorate, the United States has heightened maritime security in the area, and has announced its intention to work with Gulf Cooperation Council partners to ensure the continued flow of commerce though the strait.

For all press releases and news please contact martin@ogsmag.com

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News and features

Aberdeen Harbour growth could lead to expansion

Aberdeen Harbour has recorded a total gross vessel tonnage figure in excess of 28 million tonnes for the third year in succession, along with an increase in vessel arrival numbers.

Announcing its results for 2014, Aberdeen Harbour Board confirmed a total gross vessel tonnage figure of 28.1 million tonnes, the equivalent of almost 80,000 tonnes of shipping per day entering the port. The harbour also saw an increase in the total number of vessel arrivals, increasing from 7,834 in 2013 to 7,937 in 2014. The port also continues to experience year-on-year growth in international trade, with 2014 activity increasing by 12% on the previous year and the number of countries with which the harbour directly trades increasing to 41 in 2014. Among the new routes, the Falkland Islands alone saw more than 40,000 vessel tonnes and 10,000 tonnes of predominantly oil and gas-related cargo. This activity contributed to a turnover of £28.9 million, up

from £27.6 million in 2013, and a pre-taxprofit of £12.4 million, an increase of 29 per cent from £9.6 million in 2013. Activity to date in 2015 remains buoyant, with Q1 activity four per cent ahead of the same period last year in terms of vessel arrivals, and five per cent up in terms of shipping tonnage. As a result of these encouraging figures, said Aberdeen Harbour chief executive Colin Parker, “we remain committed to investigating expansion opportunities in Nigg Bay.” Technical, economic and environmental assessments are being finalized and subject to the necessary consents and Board approval, Aberdeen Harbour could be inviting tenders during 2016 and construction could commence in early 2017 with a view to full completion by 2020/21.

Expro awarded Statoil contract in Eastern Canada International oilfield services company Expro has secured a key contract offshore Canada with Statoil in the Flemish Pass Basin. The initial four-year contract is valued at $45 million with options for two one-year extensions. The contract will include the provision of surface well testing and subsea safety systems, drill stem testing tools, tubing conveyed perforation, downhole sampling and onsite chemistry services. Expro has provided well testing and subsea services in Eastern Canada for over 15 years and opened a state-ofthe-art operational facility in Paradise, Newfoundland in 2012. “This project will allow Expro to build on our strong global relationship and success working with Statoil,” said Mark Enget, Vice President, North America. “Expro Canada’s close working relationship with our teams in Norway provides a global network of shared expertise and skilled personnel to support Statoil’s planning and development.” Earlier this year, Expro announced a $200 million contract with Statoil providing fully integrated well testing and sampling services on the Norwegian Continental Shelf. www.ogsmag.com

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Shell:

The biggest getting bigger

Royal Dutch Shell has a strong history of growth, both organic and by acquisition, that has made it a leading force in todayâ&#x20AC;&#x2122;s global economy.

www.ogsmag.com

â&#x20AC;&#x153;Bold, strategic moves shape our industry. BG and Shell are a great fitâ&#x20AC;?

www.ogsmag.com

Shell Last month, in the biggest deal within the oil sector for more than 20 years, Shell announced a merger with its rival BG Group. The deal comes at a time of uncertainty for oil and gas companies. In the past six months the price of oil has fallen by about 50 percent. Meanwhile, analysts have warned that investment in North Sea oil exploration has all but dried up, threatening the entire industry. BG Group warned in February that it would write down the value of its oil and gas assets by nearly £6bn due to the oil price slump. Similarly, Shell announced in January that it would be cutting spending by nearly £10bn over the next three years. As it announced the takeover bid, Shell said it expected to make asset sales totalling $30bn between 2016 and 2018, although it did not specify which assets it was reviewing for sale. Asked about potential job losses in the North Sea, Shell and BG Group said they expected there to be “global synergies”, while adding that if the deal had not happened, they might both have had to make job cuts. Current BG Group chief executive Helge Lund, who took up the post last month, will remain with BG Group while the deal goes through, but is expected to leave once it is completed. Analysts gave a mixed reaction to news of the deal. Investec analyst Neil Morton said a tie-up had “been mooted for about 20 years”. He added: “BG investors receive what we see as a compelling offer. For Shell shareholders, we are less convinced of the merits. The deal is predicated on a strong recovery in oil prices ($90 per barrel from 2018), while we suspect that Shell is pouncing on BG’s imminent free cash flow to protect its burdensome dividend payout.” Christian Stadler, associate professor of strategic management at Warwick Business School, said BG would fit well with Shell’s portfolio. “Shell has a very good track record in offshore oil and gas fields, and BG will help them solidify this area,” he said. He www.ogsmag.com

â&#x20AC;&#x153;This transaction fits with our strategy and our read on the industry landscape around usâ&#x20AC;?

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Shell added that acquiring BG would help Shell’s replacement ratio: the number of oil fields Shell has lined up to replace the oil it is currently producing. But he warned cost savings would be hard to achieve and “with the current downsizing in the oil industry, you would expect some job losses”. Commenting on the takeover announcement, Jorma Ollila, Chairman of Shell said: “This is an important transaction for Shell, accelerating the delivery of our strategy for shareholders. The result will be a more competitive, stronger company for both sets of shareholders in today’s volatile oil price world. BG shareholders will receive significant value through the premium being offered for their shares. They will become shareholders in Shell, accessing an attractive dividend policy, a share in the significant synergies and the compelling upside and enhanced operating capability of the combined group. We believe that the combination is in the interests of both our companies and their shareholders.” Commenting on the combination, Ben van Beurden, CEO of Shell said: “Bold, strategic moves shape our industry. BG and Shell are a great fit. This transaction fits with our strategy and our read on the industry landscape around us. At the start of 2014, Shell embarked on an improvement programme, including divestments and the restructuring of underperforming businesses, whilst at the same time delivering profitable new projects for shareholders. This programme is delivering, at the bottom line. BG will accelerate Shell’s financial growth strategy, particularly in deep water and liquefied natural gas: two of Shell’s growth priorities and areas where the company is already one of the industry leaders. Furthermore, the addition of BG’s competitive natural gas positions makes strategic sense, ahead of the long-term growth in demand we see for this cleaner-burning fuel. This transaction will be a springboard for a faster rate of www.ogsmag.com

“BG will accelerate Shell’s financial growth strategy, particularly in deep water and liquefied natural gas: two of Shell’s growth priorities and areas where the company is already one of the industry leaders”

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Shell portfolio change, particularly in exploration and other long-term plays. We will be concentrating on fewer themes, and at a larger scale, to drive profitability and balance risk, and unlock more value from the combined portfolios. Over time, the combination will enhance our free cash flow potential, and our capacity to undertake share buybacks, where I expect to see a substantial increase in pace.” Andrew Gould, Chairman of BG also supported the combination: “This offer represents an attractive return for BG shareholders. BG has a strong portfolio of operations including growth assets in Australia and Brazil and a highly competitive LNG business, as well as an enviable track record of exploration success. The BG Board remains confident in BG’s long-term prospects under the leadership of Helge Lund. Shell’s offer, however, allows us to accelerate and de-risk the delivery of this value. The structure of the offer will provide BG shareholders with an attractive premium and a substantial cash return as well as enabling them, if they wish, to participate in the benefits of the combination through the share component. For these reasons, the BG Board recommends the offer.” The confirmation of the deal creates a company with a combined value of almost £180bn - overtaking HSBC to become the biggest on the FTSE 100 - and results in the 13th biggest merger ever. The two firms said it was expected the cash and shares transaction would be completed early next year.

Huge scale of operations: Shell Prelude FLNG The acquisition adds to Shell’s already impressive portfolio of operations, not least its investment in Shell Prelude FLNG, a floating liquefied natural gas facility to be located off the coast of Australia and the first of its kind in the world. The FLNG facility is designed to operate and stay safely moored even in the most extreme weather conditions.  The sheer size of the full-scale facility will help it to www.ogsmag.com

FMC Technologies SA Route des Clérimois - CS10705 89107 Sens Cedex France Tel. : +33 3 86 95 87 00 www.fmctechnologies.com

Heatric printed circuit heat exchangers are unlocking the future of FLNG The key technical challenge of FLNG is to take a process developed in the relatively calm, accessible and ‘spacious’ onshore environment and deploy it where few of these things are true – with all the heightened safety considerations that this brings. Heatric printed circuit heat exchangers (PCHEs) are already well-established in FPSO applications because they help simultaneously tackle the three great offshore challenges – space, weight and safety. Now they are also playing an important role in shrinking and lightening the topside bulk of the new global fleet of FLNG facilities, including Shell Prelude. A total of 18 Heatric PCHEs are being installed on Prelude. Their duties embrace a wide range of operations, among them natural gas extraction and fractionation including first and second stage cold recovery, gas dehydration, and gas and refrigerant compression. Together they save some 1500 tons of topside weight, lowering the vessel’s centre of gravity and improving stability in heavy weather. A PCHE will typically be just onefifth the size and weight of an equivalent shell and tube-type unit thanks to its exceptionally high heat transfer-to-volume ratio. But for all their light weight and compact footprint, PCHEs are still comfortably able to handle pressures up to 650 bar (almost 9450 psi) and temperatures from cryogenic to 900°C (1650°F) while delivering closely-controlled process parameters. For existing platforms, PCHEs can debottleneck and boost throughput. For newbuild projects, like FLNG, they offer the opportunity

to design-in higher levels of process efficiency, safety and durability right from the start, unlocking a host of additional financial and operational benefits along the way.

Pioneer and leader It is fair to say that no-one understands printed circuit heat exchangers (PCHEs) like Heatric. It was the pioneering research of the company’s founders that created the very ﬁrst PCHE in 1985. Only Heatric has invested continuously for more than 30 years in reﬁning and developing the technology, working with the world’s leading oil and gas companies along the way. Today the company’s 15,000m2 of advanced production facilities – a single, integrated operation which includes one of the largest radiography and pressure-testing facilities in the UK – are still unique in being dedicated exclusively to PCHE design, development and manufacture. Heatric PCHEs are fully scalable with the recently extended factory able to accommodate the construction of the highest duty exchangers either

Heatric. Leading heat transfer solutions www.heatric.com

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as single units or as multiple manifolded units – as was the case with some of the largest PCHEs provided for the Prelude project.

Light and effective The key to a Heatric PCHE’s powerful package of weight savings and capabilities is its diffusion-bonded core, which creates an exchanger with exceptionally high transfer efficiency and structural integrity. The characteristics of this design provides PCHEs with inherent and integral safety benefits which, together with a host of operational features, are of particular value to remote, floating processing applications. The seamless core construction minimises hold-up as well as vibration fracture risks, rendering PCHEs immune to catastrophic failure modes seen in other exchanger designs. Fire risks are also reduced because each PCHE is constructed entirely from stainless steel or higher alloys, with no aluminium or other low melting point material used in their construction. The future shape and disposition of a fullyfledged global FLNG fleet remains to be seen. But whatever liquefaction choices an operator makes, the compactness and robustness of PCHEs renders them uniquely able to deliver strong, powerful, structurallysimple solutions, all within an unmatched security and safety ‘envelope’.

The Shell Prelude FLNG facility will have a total storage capacity equivalent to 175 Olympic swimming pools

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Shell withstand very high winds and giant waves. In addition, it will be secured in place by one of the largest mooring systems in the world. A 93-metre (305-foot) high turret, spacious enough to house the Arc de Triomphe, will run through the facility. Four groups of mooring lines will anchor it to the seabed. The system allows the facility to turn slowly in the wind – absorbing the impact of strong weather conditions – while remaining moored over the gas field. It can stay safely moored at sea even during the most powerful cyclones. This saves valuable production days that would otherwise be lost on disconnecting the facility and moving it off the field. Three 6,700-horsepower thrusters will sit in the rear of the facility. Two of these will operate at any one time to turn the facility out of the wind and allow LNG carriers to pull safely alongside to load. The facility’s storage tanks will be below deck. They can store up to 220,000m3 of LNG, 90,000m3 of LPG, and 126,000 m3 of condensate. The total storage capacity is equivalent to around 175 Olympic swimming pools. The project will create around 350 direct and 650 indirect jobs. Recruitment of staff to operate the facility will ramp up during 2013 and 2014. Prelude will also provide taxes and revenue to Australia, create opportunities for local businesses and result in Shell spending billions in capital and operating expenditure. The Prelude FLNG Project will use significantly less materials, land and seabed area than developing the same gas via a similar onshore facility. Developing the gas at the location of the gas field will reduce impact on sensitive coastal habitats as FLNG avoids the need for shoreline pipe crossings, dredging and jetty works. Product carriers will be far from coastal reefs or whale migration routes. In December 2013 the 488-metrelong hull of Shell’s Prelude FLNG facility was floated out of the dry dock at the Samsung Heavy www.ogsmag.com

Sakhalin-2 is one of the worldâ&#x20AC;&#x2122;s largest integrated, exportoriented oil and gas projects

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Shell Industries (SHI) yard in Geoje, South Korea, where the facility is currently under construction. Once complete, Prelude FLNG will be the largest floating facility ever built. Shell’s ambition is to launch a fleet of future Preludes to pioneer a new chapter in the story of fossil fuels by opening gas fields previously thought to be too tricky or expensive to tackle.

LNG project – Sakhalin-2 Sakhalin-2 is one of the world’s largest integrated, export-oriented oil and gas projects, as well as Russia’s first offshore gas project. The project infrastructure includes three offshore platforms, an onshore processing facility, 300 kilometres of offshore pipelines and 1,600 kilometres of onshore pipelines, an oil export facility and a liquefied natural gas (LNG) plant. Sakhalin-2 is a project of many firsts. The offshore oil platform Molikpaq was the first to be installed on the Russian shelf. The Lunskoye-A and PiltunAstokhkoye-B (PA-B) platforms are also the first of their type to be installed on the shelf. The LNG plant is the first in Russia. Now that Sakhalin-2 has reached its full capacity, it takes 5% of the world’s current liquefied natural gas (LNG) market. Japan and South Korea are the main customers for oil and LNG exports. Virtually all the gas from Sakhalin-2 has now been sold under long-term contracts to customers in the Asia-Pacific region and North America. Sakhalin-2 is technically challenging. It is equivalent in size to five worldscale projects, located in a hostile sub-arctic environment, and covers a vast area in a region with almost no existing infrastructure. There are also environmental, ecological and social sensitivities to be tackled. The float-over installation of the topsides for the PA-B platform set a world record at some 28,000 tonnes. The previous record was held by the Lunskoye-A platform at 22,000 tonnes. Two 800-kilometre pipelines, which bring oil and gas from the fields in www.ogsmag.com

Zenith Consultants work across the UK and globally and have been successful in building strong working relationships with our clients across all sectors. Our Clients include some of the largest oil, gas, power and petrochemical companies in the world and we have developed a diverse portfolio of complex and interesting projects in each sector. Recently Zenith Consultants were responsible for the detailed design of a bespoke strengthening scheme for an existing multi flare support structure for Qatar Shell GTL Ltd. on the Ras Laffan site in Qatar. In conjunction with the strengthening design, Zenith Consultants were also responsible for the detailed design, procurement and supply of the specialist lifting and winching equipment to service the operation, allowing two flare tips to be replaced at any one time. The exposure of Zenith Consultants to the oil, gas, power and petrochemical industries has served to provide an excellent platform to develop the Consultancy services. In addition to our working at height and off shore abilities, we have been able to combine our skills to establish a diverse and complete business. We are able to offer full structural and civil engineering support services in conjunction with highly experienced survey and inspection capabilities. Our inspection services include (not limited to) detailed visual inspection, material NDT, verticality/tension checks and guy wire magnetic flaw detection. Zenith Consultants core values are ‘Design – Innovation – Excellence’. We work closely with all our clients to fully understand their brief and assist to value engineer solutions to minimise time and out turn costs. We are experienced at working within small working windows and utilise up to date techniques to capture key critical information in short periods of shutdown or closure to build templates of information to allow our assessments, designs and specifications to be made.

www.zenith-consultants.co.uk Tel: +44 (0)131 440 3000

If you wish to discuss any of your project requirements with a member of Zenith Consultants team please do not hesitate to contact us at: 38 Dryden Road Bilston Glen Industrial Estate Loanhead, Midlothian EH20 9LZ Scotland United Kingdom

Pearl GTL produces and processes around 1.6 billion cubic feet a day of wellhead gas

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Shell the north of the island to the icefree export terminal in the south, traverse mountainous terrain in an earthquake zone and cross more than 1,000 watercourses, many of which are ecologically sensitive.

LNG Project - Pearl GTL Shell is one of the world’s largest suppliers of natural gas. Natural gas is abundant, acceptable and affordable. Shell believes that it is an important component of a sustainable global energy mix. It is helping to meet the world’s growing energy demand while limiting CO2 emissions by delivering more cleaner burning natural gas. Shell is also pioneering new techniques to help tap difficultto-reach natural gas deposits. These include unlocking natural gas trapped tightly in rock pores, producing gas in harsh sub-Arctic conditions, and cooling gas at sea to turn it into liquid for shipment by carriers.  Shell develops groundbreaking technology that transforms natural gas into valuable liquid products and a prime example is Pearl GTL, the world’s largest gas-to-liquids plant, located in Qatar. The Pearl GTL project was developed in two phases after major construction was completed at the end of 2010. The first phase started up in early 2011 and exported the first commercial shipment of gasoil in June 2011. Phase 2 of the plant started up in early November 2011 by bringing in sour gas from offshore wells. The whole plant ramped up to full production towards the end of 2012. Pearl GTL now runs some of the largest gas processing trains in the world and is doing so safely and reliably. Upstream, Pearl GTL produces and processes around 1.6 billion cubic feet a day of wellhead gas from the world’s largest single non-associated gas field - the North Field - which stretches from Qatar’s coast out into the Gulf. The plant will process about three billion barrels-of-oil-equivalent over its lifetime. The offshore scope www.ogsmag.com

Pearl GTLâ&#x20AC;&#x2122;s water treatment plant can treat 280,000 barrels of water a day

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Shell includes 22 development wells, two unmanned wellhead platforms in about 30 metres of water and two 30-inch pipelines running about 60 km to shore. Onshore gas-processing facilities treat the sour, rich wellhead gas to remove contaminants such as metals and sulphur and further extract natural gas liquids: ethane for petrochemical processes; liquefied petroleum gas (LPG) for domestic heating and cooking; and condensates as a feedstock for refineries. Elemental sulphur produced as a by-product is turned into pellets and shipped to the nearest market to make hydrosulphuric acid, fertilizer or other valuable products. The pure gas, or methane, that remains then flows to the GTL section of the plant, where it is combined with oxygen and converted in a state of the art three-stage process into a range of gas-to-liquids products using Shell proprietary technology. The proprietary Shell Middle Distillate Synthesis (SMDS) process is at the heart of the two-train Pearl GTL plant. Developed over more than three decades, the process has been proven on a commercial scale at the 14,700-barrel-perday Bintulu GTL plant in Malaysia, which began operation in 1993. Shell has over 3,500 patents across all stages of the GTL process. The Bintulu experience helped improve the chemical catalysts integral to the SMDS process. These improvements help reduce unit capital expenditure, allow faster processing and should enable Shell to produce greater volumes of fuel and other products at Pearl. The plant includes systems to capture energy given off during the processes, converting it to steam that drives the plantâ&#x20AC;&#x2122;s compressors and generates electricity. The water recycling plant â&#x20AC;&#x201C; the largest of its kind â&#x20AC;&#x201C; treats water for re-use in steam production and cooling. It can process 45,000m3 per day of water, without discharging any liquids from the plant. Building on its extensive experience marketing GTL products from www.ogsmag.com

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Shell Bintulu, Shell exports Pearl’s high value, differentiated premium products, including GTL gasoil, kerosene, naphtha, normal paraffin and base oils for lubricants, to markets around the globe. Together with Qatargas 4, Pearl GTL represents a multi-billion dollar commitment to Qatar by Shell and the project was developed in line with its sustainable development principles. The project was designed to use technology that helps limit any environmental impact. The facility is designed to use every drop of water as part of Shell’s approach to prevent the release of any liquids from the plant. Pearl GTL’s industrial water processing plant is the world’s largest, recovering, treating and re-using all the industrial process water. With a capacity to treat 280,000 barrels a day of water, Pearl GTL’s water treatment plant is comparable to that for a city of 140,000 people.

Deepwater Project - GumusatKakap On 8 October 2014, Shell announced first oil from another major project, the Gumusut-Kakap platform off the coast of Malaysia. With an annual peak oil production of around 135,000 barrels a day, the platform contributes up to 25% of the country’s oil production. Sabah Shell Petroleum Company is the operator of the development, which employs Malaysia’s first deep-water semi-submersible production system. The field comprises 19 subsea wells, with oil exported via a 200km long pipeline to an oil and gas terminal in Kimanis, Sabah. In 2008, development drilling began in the Gumusut-Kakap field and early production started at the field in November 2012. This was ahead of engineers completing the floating production system by linking Gumusut-Kakap’s production wells to the Kikeh production facility, the country’s first deep-water development, operated by Murphy Sabah Oil. This early production was an interim measure to bring www.ogsmag.com

Early production started at the Gumusut-Kakap field in November 2012

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Shell 25,000 barrels a day on stream ahead of completing the FPS. The project has allowed Shell to share deep-water expertise with Malaysian energy companies and uses Shell Smart Fields technology to carefully control production from the undersea wells to achieve greater efficiency. Natural gas that is produced along with the oil will be re-injected into the reservoir to help improve oil recovery. With oil production now under way, work on the gas facilities is continuing with an expected start-up later this year. In Malaysia, Shell continues to run major social investment programmes focused on capacity building, environmental conservation and community development. Located off the coast of Sabah, the Gumusut-Kakap development area is particularly rich in yellow-fin tuna. Shell and the Sabah Department of Fisheries are working together on a project to enhance fishing stocks in alternative areas for local fishermen. Shell is also leading and supporting activities to promote environmental awareness in Sarawak and Sabah; for example, through the SERASI (environmentally-friendly school competition) and Nature Education Camp programmes for schools. Shell also supports research and environmental conservation efforts in Sabah’s pristine areas in Danum Valley and Maliau Basin.

Deepwater Project – Parque De Conchas Shell has been a leader in deepwater exploration and production for 30 years. Parque das Conchas (BC-10) offshore Brazil is one of its most challenging deep-water projects. Shell has a 73% interest in the project and is the operator. Parque das Conchas (BC-10) lies in around 1,780 metres of water. The heart of Parque das Conchas (BC-10) is the floating, production, storage and offloading vessel (FPSO) Espἰrito Santo with 100,000 boe per day processing capacity. Built by SBM in Singapore, www.ogsmag.com

The Perdido hull is nearly as tall as the Eiffel Tower

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Shell the FPSO was delivered to Brazil in late 2008 and moored in around 1,780 metres of water at the Parque das Conchas (BC-10) site in the Campos basin. The first phase of the project included the development of three fields tied back to the FPSO, via subsea wells and manifolds. The double-hulled FPSO’s design required significant power and heat delivery systems to drive the seabed lift equipment and process the heavy crudes. The fields came on-stream in July 2009, with this first phase involving nine producing wells and one gas injector well. By July 2013 the project had produced more than 70 million boe. Phase 2 of the project, to tie-in the Argonauta O-North field, came on stream in October 2013 with a peak production of 35,000 boe per day. In July 2013 Shell and its partners announced that they would move forward with Phase 3 of the project, which will include the installation of subsea-infrastructure at the Massa and Argonauta O-South fields. These fields will be tied-back to the Espírito Santo. Once online, Phase 3 of the BC-10 project is expected to have a peak production of 28,000 barrels of oil equivalent per day.

Deepwater project – Perdido Shell has been a leader in deepwater exploration and production in the Gulf of Mexico for over the last 30 years. Perdido in the Gulf of Mexico is one of Shell’s most challenging deep-water projects. Perdido is in a water depth of some 2,450 metres (8,000 feet). First production from Perdido was on 31 March 2010. The Perdido spar was constructed by Technip in Pori, Finland and began its 13,200-kilometre (8,202mile) journey to Texas in May 2008, arriving in the Gulf of Mexico in August 2008. The 170-metre cylindrical spar was secured to the sea floor and Shell completed the installation of the drilling and production platform on top of it. There are 22 direct vertical access wells from the spar, with capability for an additional 13 tieback wells www.ogsmag.com

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Shell from subsea completions in the area near the platform. The Perdido hull is nearly as tall as the Eiffel Tower and weighs the same as 10,000 large family cars. The Noble Clyde Boudreaux platform predrilled the 22 direct vertical access production wells. The Tobago field, which came on production in late 2011, set a world water depth record in drilling and completing a subsea well 2,934 metres below the water’s surface. This eclipsed the previous subsea water depth well record set at the Silvertip field of 2,852 metres and is nearly 40 percent deeper than the previous record of 2,118 metres, also set by Shell in the Gulf of Mexico’s Fourier field.

Complex refinery project – Port Arthur Shell has a 50 per cent ownership in the Motiva Enterprises Port Arthur Refinery (PAR) in Texas and in 2012 completed a project to expand capacity by 325,000 barrels per day (bbl/d), taking total capacity to 600,000 bbl/d. Following its expansion, the PAR is now the largest refinery in the USA and is now capable of handling most grades of crudes, even the lowest quality. A new three-unit naphtha processing complex includes a catalytic reformer, which will convert 85,000 b/d into high octane gasoline for blending. The scale of the expansion includes 725 pumps, 19 compressors, 514 heat exchangers and several new tanks. At Port Arthur, where the local community supported the expansion, more than $17 billion has been generated in regional economic development. Around 14,500 people worked on the expansion project at peak construction and more than 300 new permanent jobs were created. Strategies were implemented that improved public infrastructure and reduced the impact of construction on local communities. Shell has the largest branded fuels retailing network in the USA. The Port Arthur expansion delivers increased supplies of petrol, diesel www.ogsmag.com

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EuropEan oil & gas

Issue 108 Ref: PlastoIl Please confIRm 6 / 5 / 14 • • • •

Concept Development Engineering Construction Installation

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aPPRoval of PRoof.

Shell and aviation fuel nationally as well as for export to other countries. The refinery’s strategic location on the Gulf of Mexico allows crude oil to be brought in by sea and it has excellent links to the national fuel distribution network.

Oil Sands project – Athabasca

Canada’s oil sands are an important source of energy in a world where demand is continuing to grow.

Canada’s oil sands are an important source of energy in a world where demand is continuing to grow. At Shell’s Athabasca Oil Sands Project the oil is mined, then separated from the clay, sand and water before it is shipped by pipeline to an Upgrader at Scotford, where it is converted into synthetic crude. In 2012 it represented around 4% of Shell’s total production. The current production capacity of AOSP is 255,000 b/d of synthetic crude. Shell has plans in place for a 115, 000 b/d expansion of Muskeg River Mine and an additional 100,000 b/d from the first phase of Jackpine Mine. In addition, Shell has received conditional approval for a 100,000 b/d expansion of the Jackpine mine and submitted a regulatory application for a 200,000 b/d development of the Pierre River Mine. Shell has existing licenses for 290,000 b/d of synthetic crude production at the Scotford Upgrader and is embarking on the Quest Carbon Capture and Storage project, which would capture 1 million tonnes of CO2 per year from the Scotford Upgrader and store it permanently underground. More than 9 billion people are expected to live on Earth by 2050, up from 7 billion today. Asia’s fastgrowing cities will absorb much of this growth, with three in four people living in urban centres. Billions of people will rise out of energy poverty. As living standards improve for many across the world and more people buy their first refrigerators, computers or cars, energy use will rise. Total global energy demand could rise by up to 80% by mid-century from its level in 2000. By investing in these projects and more besides, Shell is positioned as the key player in all areas of energy provision. www.ogsmag.com

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How sustainable is shale gas? As shale gas booms in the United States, its effects and sustainability are the subject of debate. New analysis from the Worldwatch Institute explores the trends and impacts of fracking. www.ogsmag.com

nly three countries are currently producing shale gas through hydraulic fracturing (fracking) on a commercial scale: the United States, Canada and China. Key US regions for shale gas mining are Pennsylvania, New York and Texas, while most of Canada’s production comes from Alberta and Saskatchewan. All three of these countries are increasing their output, but the United States is the only country where shale gas production now exceeds that of natural gas from other sources. As several other countries are now undertaking shale resource exploration, a key question remains: what are the impacts of shale gas mining on local economies and the environment? In the Worldwatch Institute’s latest Vital Sign, Research Fellow Christoph von Friedeburg concludes that any strong national reliance on shale gas (domestic or foreign) could have undesirable consequences in both the near and long terms. Worldwide, an estimated 7,299 trillion cubic feet of shale gas is considered “technically recoverable.” However, continued exploration could lead to substantial revisions of deposits that are not merely technically, but also economically recoverable. Europe Discussions about fracking are ongoing in several European countries, including Germany, the United Kingdom and Bulgaria. But recoverable quantities of shale gas across the region remain uncertain, and many supplies are located deep underground, some in densely populated areas. Additional factors inhibiting the development of Europe’s shale gas resources include disputes about the ownership of mineral rights and substantial environmental and safety concerns. The UK government appears to be in favour of shale gas development. However, the single shale well that has been fracked in the country so far, in Lancashire in 2011, caused two earth tremors, leading to a temporary ban on fracking that was in effect until 2012. Since then, a handful of exploration wells have been drilled, but none have been 54

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fracked so far. In Romania, expectations for the country’s shale gas future have soured because of lower and lessprofitable projections of available reserves, growing public opposition to fracking, and lower oil prices, which have rendered natural gas less economically viable. Pros and cons China has invested more than $1 billion in shale gas exploration so far. But most of the country’s deposits are located in hard-toaccess mountainous areas, either at great depths or too far from the considerable water resources required for the fracking process. This makes drilling wells, as well as establishing the needed infrastructure, such as roads and pipelines, more challenging and expensive. The United States is by far the dominant producer of shale gas, producing a record 32.9 billion cubic feet per day in 2014. Proponents of fracking have touted shale gas development as a boon for local job creation. However, most of the associated jobs are temporary, and many are filled by out-of-area workers whose shortlived influx provides only passing benefit to

“Worldwide, an estimated 7,299 trillion cubic feet of shale gas is considered technically recoverable.” local economies. The development of clean, renewable energy sources, such as wind and solar, has been shown in many cases to be more successful in creating employment. The costs of damage to local roads from the heavy truck fleets

needed for well construction and wastewater transport amount to hundreds of millions of dollars. Air pollution emissions from vehicles and from well-pad diesel generators can be harmful. And the toxic wastewater that flows out from the wells after the fracking fluid is pumped underground – containing a mixture of chemicals, water and sand – is often inadequately treated, presenting a danger to soils and aquifers. Such impacts need to be assessed closely within the United States as well as in other countries that are

Shale gas

considering shale gas development. The shift in the United States from coal to natural gas for power generation has helped to reduce domestic greenhouse gas emissions in the short term. But the long-term, global benefit of this reduction is less certain, as fracking releases large quantities of methane â&#x20AC;&#x201C; a more potent contributor to atmospheric warming than carbon dioxide â&#x20AC;&#x201C; and because growing amounts of US coal have found their way to export markets. Furthermore, optimistic projections of future US shale gas

production have been called into question. An intense debate has also arisen about possible US natural gas exports and their destinations. In most cases the gas needs to be liquefied in large facilities, transferred to shipboard tanks, and re- gasified at the destination. These processes add up to $4 per thousand cubic feet to the cost, making competition with locally available pipeline imports more challenging and reducing profitability. The prospect of substantial LNG exports has also

raised concerns within the United States that domestic natural gas prices could be driven up again, making energy more expensive. Christoph von Friedeburg is a research fellow at Worldwatch Institute, an independent research organization based in Washington, DC that works on energy, resource, and environmental issues. Visit www.worldwatch.org to obtain a copy of the full report, Effects and sustainability of the US shale gas boom. www.ogsmag.com

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A weather eye Medium range weather forecasting can have a significant effect on the bottom line for oil operators. MeteoGroup explains how it works www.ogsmag.com

ne of the most difficult jobs facing project managers moving critical resources in the North Sea is planning ahead for what are often referred to as ‘medium range weather impacted events’. Forecasting weather over longer periods (typically up to 15 days in advance, often termed medium range forecasts) is extremely difficult with any degree of accuracy because of the volatile and chaotic nature of the atmosphere. Very small variations in the initial conditions of a computer forecast model can lead to huge variations in the forecast – a phenomenon known as the ‘butterfly effect’. This is why forecasters can typically only forecast conditions up to roughly three days ahead with any degree of precision. Beyond this time scale, conditions become significantly more influenced by these tiny initial variations. The key to understanding medium range weather forecasting lies in an understanding of how to deal with uncertainty. Weather forecasting is a risk related activity because forecasters are dealing with uncertainty. One of the best ways to deal with any risk assessment activity is to use probability as the mechanism of measurement.

Probability & weather

Probability deals with the likelihood of an event occurring. Probability weather forecasting therefore specifies how likely a defined weather event is to occur on a particular occasion and represents that probability as a percentage. A probability of 10% means that the

“Very small variations in the initial conditions of a computer forecast model can lead to huge variations in the forecast” forecast event will occur 10 times out of 100 or the odds against the event occurring are 1 in 10. Even a low probability of an event occurring can provide a useful warning of a 58

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serious event likely to cause significant disruption. Even though there is a 90% probability that the event will not occur, knowledge of the 10% risk enables users to prepare for the worst, eliminating the element of surprise. The remaining time the forecast event does not occur is referred to as false alarms. For a project manager tasked with an expensive rig move 15 days ahead, the degree of probability upon which he/ she decides to set as a threshold will be determined by their individual attitude to risk, the cost variables involved in mobilising that far in advance (against the profits involved in early mobilisation), and the losses involved in missing the deadline and having to wait a further 15 days until favourable conditions re-occur. Improving probability also relates to the occurrence of particular weather

related events occurring at a specific location, eg the likelihood of a given wind speed, swell height or significant wave height occurring at a precise location, such as an oil platform at a specified latitude and longitude in the North Sea. This is called setting threshold levels. Working with a meteorologist to define the thresholds required for a given operation helps to define the probabilities of the event occurring and helps to minimise the degree of uncertainty around the weather impact on the operation. Regardless of the probability however, there still exists a degree of uncertainty reflected in the percentage given. To further reduce this degree of uncertainty, meteorologists use a system called ensemble forecasting.

Ensemble prediction system (EPS)

In 1992 The European Centre for

A weather eye

Medium Range Weather Forecasting (ECMWF) pioneered an ensemble prediction system for use by national meteorological organisations and private weather providers. The ECMWF is an international organisation supported by 21 European member states and 13 cooperating states, including the UK. Specialising in numerical weather prediction for medium range weather forecasting, the ECMWF operates one of the most powerful supercomputer complexes in Europe; it does not issue weather forecasts itself, but distributes its products to weather providers across its member states. Instead of running a forecast model once (deterministic forecast), ensemble forecasts run the model 50 times from slightly different initial conditions. Each forecast in an ensemble is called a ‘member’ and the

relationship between each member, over a number of days ahead, defines the accuracy of the forecast. If all ensemble members are similar then forecasters will have a high degree of confidence that the forecast will be reliable. Probabilistic ensemble forecasting based on a precise location and pre-set thresholds can prove an invaluable tool for project managers operating in the North Sea by helping to understand the effect of weather impacted events on operational planning. Evidence suggests that when medium range weather forecasting (probabilistic) is used intelligently with deterministic forecasts the results equate to an improved bottom line. The reason for this is simple; while probabilistic forecasts still equate to a degree of missed opportunities (reflecting the individual’s attitude to

risk against the required percentage of the event not occurring) they also allow for operations to be more prepared and ready to take advantage of a greater number of weather windows occurring. For those still relying on deterministic forecasts, it must be remembered that every time a forecaster issues a deterministic forecast the underlying uncertainty still exists, and the accuracy of the forecast depends on the skill and experience of the forecaster in the same way as probabilistic forecasts do. MeteoGroup is Europe’s largest independent weather forecasting company. MeteoGroup Offshore provides custom solutions for all offshore operations including exploration & production, dredging, engineering & facilities solutions, subsea, salvage, renewables, dive vessels & drilling and survey operations. www. meteogroup.com www.ogsmag.com

Interview: Niels V. Pedersen, master mariner Niels V. Pedersen is an experienced master mariner and captain of the first ever Triple E container ship, the 400-metre Mærsk Mc-Kinney Møller. He talks exclusively about the engineering marvel named in 2013 after the late Arnold Mærsk Mc-Kinney Møller, founder of the AP Møller-Mærsk Group. What is it like to be captain of an iconic vessel? I have always enjoyed being a captain. I like the responsibility, the cooperation between the team on board, and with my company, agents, customers and media around the world. I also like the interest shown in the vessel and my company from all over the globe. Even after almost two years, my colleague Captain and I participate in many media and customer events, live TV, documentaries, interviews, etc. I like to be a part of the game. And, of course, I love to sail and explore the sea. What makes the Mc-Kinney Møller team special? Ever since the maiden voyage the team has been hand picked. All 60

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crew members are very dedicated, and work hard to make sure everything runs smoothly. What has been your greatest challenge on the Mc-Kinney Møller? The maiden voyage was a great challenge - especially the first six months after delivery of the vessel. A vessel like this is delivered “empty”, meaning that the crew has to fill up all the store rooms, offices, provision rooms, maintenance, and prepare for the first audit, etc, at the same time as keeping the vessel on schedule. How concerned are you about piracy? I am not very concerned about piracy, but of course it’s on my mind. We have procedures when

Interview

transiting the piracy areas, which I cannot go into detail about. If you were not a master mariner, what career would you have pursued? Airline pilot, for sure. My father was a pilot, and some of my very closest friends are working in the airline industry as both captains/pilots and mechanics. I love to hear them tell stories about their work. What is the first thing you do when you reach dry land? If I have the time the first thing I always do is to go and have some local food and enjoy life in the various countries we reach. One of the first things is also to buy gifts for my wife and two children! I live in a small town in Denmark named Hundested, by the sea. When I arrive at home after months at sea, I love being with my family again, and enjoy time off for some months. What would you say to a friend or family member if they told you they were planning to follow your footsteps?

I would tell them that they were bound for a great and interesting job in a very high-tech world. That means travelling, a lot of technical insight, and working in close cooperation with a multi-national crew. Favourite book: I have many favourite books, but generally I love reading biographies. Favourite ship: I have had many favourite ships, but at the moment my favourite is the iconic MĂŚrsk Mc-Kinney MĂ¸ller. I think that most captains like the vessel they are in command of, and are very dedicated to it. First published by P. Gonzalez- Morgan in Gibraltar Shipping, March 2015 @ShippingGib www.ogsmag.com 61

Opening locks Dr. David L. Blond wonders how much new traffic will be attracted to the Panama Canal when the new locks are opened

ometime in 2016 water will flow into the new, enlarged, third set of locks for the Panama Canal. It will be the first expansion of the Canal since it was completed over 100 years ago. With the increasing size of ships, more and more high value cargos are being carried on vessels too big for the Canal’s existing locks (Panamax), so the Canal decided in 2006 to add a third set of larger locks as well as channel deepening and widening. In a way I’ve had a hand in this, but I’m not sure that my work has always been appreciated. Around 1987 at DRI we launched the World Seatrade Service. The Canal Authority, then a US government operation, was a client. 62

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When you analyze the flow of traffic through the Canal before the addition of the new locks, it is clear that much of it is inter-Latin America or unidirectional trade at certain times of the year from the US Gulf carrying grain to Asia. The question that Panama asked me to investigate over the years was how much new cargo they could expect to have running through the Canal as a result of adding extra capacity. I have some interesting memories of working with the Canal Authority. Around 1998 I was asked to develop a price elasticity model for measuring the impact of changes in tolls on Canal traffic. This was a year before the Canal was handed over to the Panamanians. Using PCC (later changed after Panama took the Canal to PCA) data on ship transits by size, class and commodity, I built a price elasticity model, the first one ever, and went down to Panama to present the findings to the full Board made up of Panamanians and Americans. The elasticity of price to transits for bulk ships fit nicely with expectations – between 1 and just under 2. Bulkers can go to South America and their cargos are not very time sensitive. Price matters when deciding which route to go. But liners with their regular schedules are less elastic to price changes. As I recall they sat in the 0.6 to 0.8 range, again fitting our expectations. This meant that they could raise rates on lines and expect to earn back more in

Opening locks

revenues than was lost in fewer transits. I presented the result to the Board – dead silence at first, and then a push back. How could small changes in tariffs prevent some traffic using the Canal, they argued? They were frightened by the implications that operators might not use the Canal if they incrementally raised the tolls. After leaving the meeting, the Director of Forecasting was called in. He came out white faced. All 100 copies of our report were collected and then burned. A couple of years later, the staff tracked me down and asked me to build for them a more elaborate model to predict future traffic, revenues and trade through an enlarged Canal. It had to be self contained, updated internally using feed directly from weekly traffic data, and allow for the inclusion, starting around 2016, of additional capacity capable of hosting larger vessels than Panamax. After months of work we installed this self-contained integrated planning model on Canal Authority computers and trained staff to use it. But we received payment only because the Director was out of the country predicting future volume through the Canal significantly greater than the volumes my model said would likely pass through the Canal. A year later I received a call from another consultant hired to check out independently my estimates. They had unfortunately come up with a number within a tenth of a percent of our number and they had to go to court to get paid. The Government of Panama has spent nearly $6

billion dollars on adding new capacity, and we will not know for many years whether it will prove to be a wise investment. When the Canal was built, ships were a fraction of the size of the locks. It took nearly a hundred years for them to reach the capacity of the original Canal. How long it will take to maximize the potential of the expansion is unclear, but what is clear is that globalization’s golden age has passed. With global growth slow and with more questions raised about the benefits versus the costs of open markets, it is likely that long-term growth in world trade will barely be faster than worldwide growth in output. My global trade model forecasts an optimistic growth rate of between 4.5% and 5.5% between 2015 and 2025. There is a risk that the Government of Panama’s gamble to add the third set of locks may not pay off, but it’s a gamble they had to take. Without locks capable of handling the largest ships, the route through the Isthmus would have become a footnote to maritime history.

Dr. David L Blond is President of Quantitative Economic Research International www.ogsmag.com

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Offshore Europe 2015 EXHIBITION AND CONFERENCE SIGN UP AT

8-11 SEPT 2015

OFFSHORE-EUROPE.CO.UK/ ATTEND

ABERDEEN, UK

SPE OFFSHORE EUROPE

LEADING INTERNATIONAL E&P EVENT MEET FACE-TO-FACE WITH 1,500 EXHIBITORS

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ACCESS NEW TECHNOLOGIES ACROSS THE E&P VALUE CHAIN

Impressed by the number of exhibitors covering all aspects of the oil and gas industry particularly the focus on subsea.

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The worldwide development of deep and ultra-deep field discoveries is essential for sustainable oil and gas production. Our Deepwater Zone showcases the advanced subsea, seabed and floating production hardware and expertise being utilised in these frontier projects. Benefit too from meeting suppliers from Aberdeen, a major global exporter of subsea products and services.

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PEOPLE • TECHNOLOGY • BUSINESS Keynote Programme

Technical Programme

Hear senior global representatives and government officials debate current issues and critical future trends in the E&P industry, at the free to attend Keynote Programme.

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The Keynote Programme will focus on the basic challenge of meeting energy demand while balancing concerns over climate change, security of supply and consumer affordability. This challenge incorporates related issues: the well-being of our people and neighbouring communities, environmental risks and the safety and security of upstream assets. MICHAEL ENGELL-JENSEN, SPE OFFSHORE EUROPE 2015 KEYNOTE CHAIRMAN

Over 100 selected papers will feature in the 2015 Technical Programme, which will cover the breadth of the E&P value chain with expertise from across the globe.

“

Whilst we continue to push the boundaries of technology and innovation, we must find better ways to attract and encourage the next generation of talent into our industry. For the first time we are inviting technical papers based on both people and technical challenges, to address both aspects in parallel. CHARLES WOODBURN, SPE OFFSHORE EUROPE 2015 TECHNICAL CHAIRMAN

TECHNICAL SESSIONS WILL INCLUDE:

> DEVELOPING TALENT TO MEET DEMAND Insight on current challenges and best practices to develop our young and experienced professionals.

> HSE - A FOCUS ON PROCESS SAFETY New insights into health, safety and environmental management with a specific focus on process safety.

> FIELD RESTORATION (WELL ABANDONMENT & DECOMMISSIONING) The latest legislation, practices, case studies and activity with regards to well abandonment, abandoned well monitoring and the decommissioning of platform and pipeline infrastructure.

> SMARTER AND MORE EFFICIENT FIELD DEVELOPMENT The latest practices, concepts and case studies on the innovative, efficient and smarter development of offshore oil and gas fields. > ASSET & WELL INTEGRITY Advancements in assessing, monitoring, managing and assuring the integrity of the well, production facilities and field infrastructure. > SUBSEA Insight into latest drilling, completion, intervention and production technologies for subsea developments.

“

> MAXIMISING RECOVERY The latest technical advancements in sub-surface practices and technologies to enhance production and increase the recovery of mature fields. > SHALE AND OTHER UNCONVENTIONAL HYDROCARBONS The latest technologies, practices, legislation and general state of this area of the industry.

SPE Offshore Europe helps me keep up to date with “step changes” in our industry. MECHANICAL ENGINEER, AMEC

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SYSTEMs

Vulcan Thermal Desorption Unit Vulcan® Systems provides custom-built thermal desorption solutions for the remediation of drilling wastes, petroleum-contaminated soils and a variety of other materials. The Vulcan® Indirect Fired Thermal Desorption Unit can be custom-designed and manufactured to provide a thermal solution for numerous environmental issues, including drill cuttings, drilling muds, and soil remediation. This indirect fired system thoroughly processes and remediates drilling wastes and soils contaminated with petroleum hydrocarbons. With our engineering design, set-up and commissioning support and aftersales services, Vulcan® Systems offers comprehensive thermal solutions to meet each client’s individual project needs. 68

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Vulcan Systems

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Leading the way in Thermal Desorption Technology

are created in the earth. These holes are drilled for the extraction of oil and gas, as well as for core sampling and other purposes. Drilling mud aids in the borehole drilling process by acting as While the oil and gas industry may fluctuate, the lubricant for the drill bit while also transporting presence of drilling waste remains consistent—as drill cuttings—another form of drilling waste— does the need to dispose of that waste. Operators to the surface. Drill cuttings are broken pieces of are often on the lookout for innovative ways solid material that are created to handle, treat and even reuse as the drill bit penetrates waste from oil and natural gas “Drill cuttings and drilling and breaks the rock. As the drilling processes. drilling mud circulates up muds can be treated from the drill bit, it carries the Drilling mud, also known as drilling fluid, is one of these for beneficial reuse.” drill cuttings up to the surface, where the mud and cuttings common wastes and an essential must be separated before recovery. component of the drilling process. In oil and gas drilling operations, drilling muds are used to Thermal treatment presents operators with the control subsurface pressures, lubricate the drill opportunity to remediate and reuse drilling bit, stabilize the well bore and transport drill wastes. With the use of a thermal desorption cuttings to the surface. unit, drill cuttings and drilling muds can be treated for beneficial reuse. During the oil and gas drilling process, boreholes

Drilling Wastes: Recovery and Beneficial Reuse

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Types of Drilling Muds Depending on the application, one of three types of drilling muds may be used: water-based muds (WBMs), oil-based muds (OBMs) or syntheticbased muds (SBMs). Oil-based muds are one of the most effective drilling fluids, but many wells, especially in the southern gas basin of the North Sea, are drilled with water-based muds. Synthetic-based muds have a lower environmental impact and biodegrade more quickly, making SBMs one of the more frequently used types of drilling fluids. Water-based muds are produced with water mixed with clays and other chemicals to create a homogenous blend. WBMs generally consist of bentonite clay with additives such as barium sulfate, calcium carbonate or hematite. Thickeners, such as xanthan gum, glycol and starch, may also be used to influence the mud’s viscosity. Oil-based muds have a base fluid consisting of a petroleum product like diesel fuel. Because of their increased lubricity, enhanced shale inhibition and greater cleaning abilities, OBMs are more frequently used than WBMs. OBMs are also able to withstand greater heat without breaking down. Synthetic-based muds possess a base fluid of synthetic oil. These muds are most frequently used on offshore rigs because they have the same properties as OBMs but a toxicity of fluid fumes that is significantly lower.

Drilling Waste Disposal and Recovery

Vulcan Systems

After the drilling job is complete, the drilling wastes must be disposed of in some way. The U.S. Environmental Protection Agency (EPA) classifies drilling fluids as “special waste,” meaning that they are exempt from many federal regulations. Because of this classification, laws governing the disposal of drilling muds vary from state to state. In California, for example, the state government has a strict set of regulations for drilling wastes and requires operators to obtain approval before they may begin any type of disposal. In 2012, an oil company in Texas had to pay a $1.35 million fine after drilling waste that was placed on their “landfarm” contaminated nearby water sources. Landfarms are privately-owned, state-regulated fields where drilling waste is spread, and while they are legal, they are capable of causing damage to the surrounding environment. Drilling waste, even when buried, can easily contaminate soil and groundwater when the hydrocarbons and other chemicals leach into the earth. While most water-based muds are disposed of when the drilling job is completed, many oil-based and synthetic-based muds can actually be recycled. Drill cuttings can also be recycled and reused, after the hydrocarbons are removed. On a standard drilling rig, there are a variety of relatively simple processes that can be used to capture clean mud that would otherwise be discarded and put it to beneficial reuse. Throughout the drilling process, for example, drilling fluids are recirculated, which aids in decreasing waste by reusing as much mud as possible. Even the recovery of drilling fluids during tank cleaning may present an opportunity for reuse. Drilling mud transports the drill cuttings back to the surface in order to prevent the well from clogging. On the drilling rig, the cuttings are separated from the mud, and the mud is recycled for reuse. The drill cuttings, meanwhile, are either discharged to the seabed, re-injected into the well or taken ashore for treatment and disposal. These cuttings vary in size and texture, depending on the type of rock and drill used. Drill cuttings can range in size from fine sand to gravel. While drill cuttings are often disposed of after the drilling operation is finished, they can actually be treated and beneficially reused. Before drill cuttings can be reused, however, it is necessary to ensure that the hydrocarbon content, moisture content, salinity and clay content are suitable for the cuttings’ intended use.

There are numerous applications for recycled drill cuttings, such as the stabilization of surfaces that are vulnerable to erosion, like roads and drilling pads. Oily drill cuttings can also serve the same function as traditional tar-and-chip road surfacing. Cuttings can also be used as aggregate or filler in concrete, brick or block manufacturing, as construction material or as daily cover at landfills. Recycled cuttings may also be used in the production of cement. Research has even been done on additional uses for recycled drill cuttings. There have been trials conducted in the United Kingdom to determine the feasibility of utilizing oily drill cuttings as fuel for power plants. In the U.S. the Department of Energy has researched the possibility of using drill cuttings as a substrate for restoring coastal wetlands. www.ogsmag.com

Vulcan® Thermal Desorption Units The Vulcan® Indirect Fired Thermal Desorption Unit, as shown below, is a new 6’ diameter x 35’ long heated zone 304 stainless steel rotary kiln with combustion chamber. This system is specifically designed to remediate soils and drilling muds contaminated with petroleum hydrocarbons. Consisting of a primary treatment unit, quench scrubber, knock-out pot, oil/water separator, secondary treatment unit, air-cooled helical rotary liquid chiller induced draft fan, discharge system and control room. In the process, the drilling mud is transferred to the feed hopper of the Primary Treatment Unit (PTU) with the client’s backhoe or skid loader. The material is then fed to a feed hopper mounted on a pugmill. From the pugmill, the material is transferred to the feed auger, which conveys the drilling mud into the PTU and maintains a seal/airlock for the system. The indirect fired rotary kiln has three heat zones, and the operating temperature of the drum can reach up to 950 degrees Fahrenheit (510 Celsius). The rotary kiln is housed in a combustion chamber with six 2.7 MMBtu/hour burners, producing a total of 16.2 MMBtu/hour of heat. The kiln operates in an oxygen-deficient and slightly negative atmosphere. Vapors from the contaminated drilling muds are pulled out of the system in a countercurrent direction to

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the material flow. The vapor from the PTU is pulled into a high-efficiency quench scrubber that uses oil as the quench liquid. The quench operates at 250 degrees Fahrenheit (121 Celsius) and removes dust particulate, in addition to condensing the heavier hydrocarbons in the vapor stream. The condensed oil and sludge are pumped through a set of filters to an oil/water separator and then to an onsite storage tank (to be supplied by client). The vapor that is not condensed in the quench scrubber is pulled through the knock-out pot, the custom-built vertical helical heat exchanger, which reduces the temperature to 70 degrees Fahrenheit (21 Celsius). The fluid from the knock-out pot—condensed water and oil—is pumped to an oil/water separator, then to a water and oil holding tank (to be supplied by client). The non-condensable gases are pulled from the knock-out pot by an induced draft fan and pushed into the secondary treatment unit, where all remaining hydrocarbons are destroyed at temperatures of up to 2,000 degrees Fahrenheit (1,093 Celsius) with a residence time of up to two seconds.

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Thermal Treatment of Drilling Wastes The best method for unlocking all the potential uses of drilling wastes is through thermal treatment technologies, such as thermal desorption. Through the use of extremely high temperatures, thermal treatment reclaims or destroys hydrocarboncontaminated materials, such as drilling wastes. Thermal processes are the most efficient treatment for destroying organics, capable of reducing the volume and mobility of inorganics like metals and salts. Waste streams that are particularly high in hydrocarbons, such as oil-based muds, are excellent candidates for thermal treatment.

may be a final treatment process, resulting in inert solids, water and recovered base fluids. Through the application of heat, thermal desorption vaporizes volatiles and semi-volatiles and easily removes light hydrocarbons and aromatics. The process produces a variety of secondary waste streams, including solids, water condensate and oil condensate.

Rotary kilns and hot oil processors are the most frequently used equipment and most proven methods for the thermal desorption of drilling wastes. Indirect fired rotary kilns use hot exhaust gases from fuel combustion to heat drilling muds and drill cuttings. This type of kiln consists of a rotating drum placed inside a jacket. Heat for the process is provided through Thermal treatment may be a the wall of the drum by the hot short-term process to reduce exhaust gas that flows between the toxicity and volume, as well as prepare waste materials for further jacket and the drum. The drilling wastes are transported through treatment and disposal, or it the drum as it rotates, and the

treated solids are recirculated to prevent a layer of dried clay from forming inside the drum. A vapor recovery unit can be used to recover or condense hydrocarbons from the gas stream extracted out of the thermal desorption unit. The hydrocarbons are not destroyed but may be reused in the process as an alternative fuel source or sold as a by-product. Vapor recovery units from Vulcan速 Systems typically consist of a quench scrubber, mist eliminator, shell and tube heat exchanger, knock-out pot, oil/water separator and pre-combustion chamber. Depending on the process and material, optional items can be added to the process, including baghouses, thermal oxidizers or acid scrubbers. Vulcan速 Systems is able to offer estimates to design a vapor recovery unit to suit specific applications, as well as to meet environmental and emissions standards. www.ogsmag.com

SYSTEMs

Capturing Mercury Emissions

Industrial processes that use mercury, waste generators and mineral mining operations all contribute to mercury pollution. Poor management of emissions or leakage can result in concentrations of mercury in the soil that are well above the regulatory limits. In 2007, the EPA reported that mercury was a â&#x20AC;&#x153;contaminant of concernâ&#x20AC;? at nearly 300 Superfund sites across the country. As a result, the EPA and other organizations around the globe have tightened regulations on emissions of hazardous chemicals, such as mercury. 76

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Fortunately, mercury can be cost-effectively removed from soil before it has a chance to negatively impact human health and the environment. Mercury can be removed from contaminated substrates through the use of thermal desorption. In this process, intense heat is applied to the material to volatize the mercury without damaging the material itself. In a thermal desorption unit, the contaminated soil is heated and the mercury is vaporized. A gas or vacuum system then transports the vaporized mercury and water to an air-emission treatment system.

Vulcan Systems Vulcan速 Systems is uniquely positioned to aid those in the industry in the removal of mercury and mercury products from contaminated materials. Vulcan速 has developed technology to remove mercury from substrates on a continuous basis. Our custom-designed and manufactured thermal equipment includes vapor recovery for the collection of vaporized mercury and has been demonstrated on both a pilot plant and a commercial basis. Our highly qualified staff is capable of designing systems to remove mercury from any industrial powders, such as activated carbon, fluorescent lamp powder, sludges and soil contaminated with mercury and mercury compounds. Mercury can be captured from cement kiln dust (CKD), eliminating over 99 percent of mercury and helping U.S. cement plants to adhere to the 2015 National Emission Standard for Hazardous Air Pollutants (NESHAP) regulations. Capturing mercury also presents more opportunities for raw material use for cement producers. This process can also be applied to a variety of other materials, including coal ash, activated carbon, clay and other industrial dusts. Mercury capture results in an almost mercury-free raw material and an insoluble concentrated form of mercury, which can be safely cast into concrete, disposed of or recovered. Mercury capture is an innovative method to reduce mercury emissions from cement kiln exhaust stacks and other emission sources. This technology can be utilized to capture both elemental and ionic forms of mercury. Mercury capture involves the use of thermal desorption to separate mercury from CKD, allowing the dust, essentially free of mercury, to be recycled and used anywhere within the process. This innovative process helps cement plants to meet the new NESHAP regulations, which will be in place in September 2015.

For more information on Vulcan速 Systems, visit our website, www.getavulcan.com, or contact Worldwide Recycling Equipment Sales, LLC at +1 (660) 263-7575 or wwrequip@wwrequip.com.

Custom Designed Solutions For a smaller, portable solution, the Vulcan速 Mobile Thermal Desorption Unit is a one ton per hour indirect thermal desorption system designed to remediate drill cuttings. This compact, mobile unit provides thorough remediation of drill cuttings contaminated with petroleum hydrocarbons. Optional components, including acid scrubbers and a flameless electric thermal oxidizer, may be added to the system for an additional cost. Recovering drill cuttings and drilling muds is often practical and cost-effective environmentally sustainable process. Recycling and reusing drilling wastes can help operators meet disposal regulations, reduce disposal costs, limit truck traffic and save money on building well pads and roads. The proper disposal of such wastes prevents the contamination of water supplies and the soil. Thermal treatment of drill cuttings not only reduces their volume but also enables operators to recover reusable drilling fluids, resulting in significant cost savings while also augmenting environmental performance.

Mercy Ships: The free floating hospital Using the worldâ&#x20AC;&#x2122;s largest civilian hospital ship, the international charity Mercy Ships provides free medical and humanitarian aid to some of Africaâ&#x20AC;&#x2122;s most deprived communities 78

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ercy Ships is an international charity that provides free medical and humanitarian aid through the deployment of the world’s largest civilian hospital ship, the Africa Mercy. It’s a simple idea – a floating hospital, staffed by a multi-national team of compassionate and highly-skilled volunteers, and docks in some of the poorest countries in the African continent to serve those most in need of free medical care and assistance. The primary aim of the organisation is to increase access to healthcare throughout the world, working with host nations to fill the gaps in healthcare systems while serving the dire and immediate needs of their population. With 75% of the world’s population living within 150km of a port city, Mercy Ships is able to reach many of those who live with little or no access to healthcare in some of the poorest parts of the world. The Africa Mercy is a floating hospital, so Mercy Ships has no need to invest time and money building hospitals www.ogsmag.com

Screening in Togo

in every country it visits. A key goal of the charity, however, is to leave a lasting legacy in all of the developing nations it docks in. By collaborating with qualified local and international partners, Mercy Ships provides a variety of training opportunities for medical professionals (surgeons, nurses, anaesthesia providers, administrators and community 80

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health workers), along with curative surgical interventions. Mercy Ships programmes offer holistic support to developing nations striving to make health care accessible for all; this is done through a range of land based projects which focus on agriculture and construction for local healthcare services. Since 1978, Mercy Ships has

delivered healthcare services to more than 2.5 million direct beneficiaries, visiting more than 451 ports in developing nations around the world, bringing lasting change to millions of lives. The countries served by Mercy Ships are ranked as the poorest in the world by the United Nations Human Development Index (UN HDI).

Mercy Ships

“Mercy Ships have visited more than 451 ports in developing nations around the world since 1978, bringing lasting change to millions of people” The ship is currently docked in Madagascar, an island nation off the coast of Southeast Africa, which is positioned 151st out of 187 countries measured by the UN HDI. With over 90% of the population living on less than 75 pence a day, and with only two physicians and three hospital beds available for every 10,000 people, the situation in Madagascar is rather desperate. The Africa Mercy has been converted from a Danish rail ferry to a state-ofthe-art hospital ship, with the hospital covering most of the original rail deck, which is approx 1,200 m2. Throughout its history, Mercy Ships has had between one and three ships in service and since the deployment of the Africa Mercy in 2007, the charity has been committed to adding another ship to the fleet by July 2017—the Atlantic Mercy. The Africa Mercy is currently the only Mercy Ship in service, but it represents greater capacity than all prior hospital ships combined, with five operating theatres, X-ray facilities and a CT scanner, a pharmacy and a laboratory on-board. In addition to this, on the Africa Mercy there is capacity for 82 in-patients with four wards and a small intensive care unit, as well as housing over 450 volunteers who come from 40 different nations to serve on the ship every year. During each field service, volunteer crews carry out eye surgeries, eye training, maxillofacial surgeries, reconstructive surgeries, general surgeries, VVF surgeries, dental care and basic oral health education. Mercy Ships has provided services and materials in developing nations valued at over $1.2 billion, including the following: • Performed more than 78,000 life-changing operations such as cleft lip and palate repair, cataract removal, orthopaedic procedures, facial reconstruction and

obstetric fistula repair. • Treated over 183,000 dental patients including over 353,000 dental procedures. • Trained more than 5,800 local teachers who have in turn trained many more. • Trained over 35,300 local professionals in their area of expertise (for instance anaesthesiology, midwifery, sterilisation, orthopaedic and reconstructive surgery, and nursing). • Taught over 183,000 local people in basic health care. • Completed over 1,100 community development projects focusing on water and sanitation, education, infrastructure development and agriculture. Mercy Ships is funded by an increasing number of committed supporters, including individuals, rotary clubs, trusts, schools, churches, and companies. Every pound that Mercy Ships receives is complemented by over two pounds in contributed gifts-in-kind and services. Most significantly, those serving on the ships - including the captain, surgeons, nurses, chefs, engineers, electricians and cleaning staff - contribute monthly crew fees and raise their own finances to serve with Mercy Ships. For these reasons, the return on investment for Mercy Ships is nothing less than extraordinary. Mercy Ships programmes promote health and well-being by empowering developing nations through capacity building and by meeting the urgent surgical needs of the world’s forgotten poor. For hundreds of thousands of suffering people, the words ‘Mercy Ships’ promise a brighter future, a cure from physical deformities and ailments, an escape from poverty and a sense of self-worth.

If you would like further information about the work of Mercy Ships, please visit www.mercyships.org.uk or contact info@mercyships.org.uk.