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

ISSUE 84 www.ogsmag.com

Maersk Oil: Developing North Sea Fields

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• The Editor

A good gag In which Arthur tells Martha about the climate joke

“I

heard this stand-up comedian on the radio the other day,” said Arthur. “How do you know he was standing up,” said Martha, ever the practical one, “if it was on the radio?” “Had to be,” said Arthur, as if he knew all about comedy. “You couldn’t deliver lines like that sitting down.” “OK,” said Martha, “what was so funny?” “Well,” said Arthur, “he set the scene by telling us how we had to be good stewards of the planet and not let the world warm up too much.” “Why bother?” said Martha. “If it gets too warm we’ll just turn the air conditioning on.” “Oh, but you can’t,” said Arthur, “because that’s what’s making us overheat.” “What kind of nonsense is that?” said Martha. “If you turn the air conditioning on it gets cooler, not warmer.” “Yes,” said Arthur, “inside it does, but he was talking about

Editor

The

Martin Ashcroft

outside, and that’s why it was so funny. Just hear me out.” “This had better be good,” said Martha. “It is,” said Arthur, “because after he told us how we were burning too much oil, he went on to say how much more of the stuff we had been discovering lately and exactly what we should do with it.” “And what was that?” said Martha. “He said we should . . . “ Arthur stifled a chuckle to add suspense, then burst out with the punch line. “He said we should leave it in the ground!!” “That’s brilliant,” agreed Martha. “It gets better,” said Arthur, “because the radio announcer came on afterwards and said that the comedian was a US Senator! I couldn’t believe it. You don’t hear a gag as good as that every day from a US senator, now, do you?” “I suppose not,” said Martha. “I haven’t heard one as good as that since they started paying farmers not to grow anything.” •

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Contents Page 18

Cover story: Maersk Oil: Developing North Sea Fields

The Editor: A good gag

Ineos to acquire North Sea gas fields

News in brief

Balltec lifts gas compression facility

Oil slump hits BP quarterly profits

LNG shipping freight rates are under pressure

Satellite communications growing in O&G market

Interview: Masamichi Morooka

EBH Namibia employees trained by Rolls Royce

People first by Donna Smith

Datum 360 partners Perfect Projects Inc.

Mercy Ships: British second officer navigates

Indonesia rejoining OPEC

New pipeline projects

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• News & features

News in Brief Brodosplit, owner of Croatia’s largest shipyard, has implemented an AVEVA Integrated Shipbuilding solution. “Our key objective was to improve shipyard efficiency and productivity,” said Robert Pešut, R&D Director, Brodosplit. “We underwent a significant market evaluation before selecting AVEVA’s Integrated Shipbuilding solution, which was by far the best in the market. It was encouraging to hear that AVEVA’s marine software is used by many of the world’s most productive shipyards.” * * *

A recent survey has found that the marine industry may be neglecting its machinery maintenance. HBCradiomatic UK, a manufacturer of radio systems for wireless control machinery, has found that 40% of its radio-controlled units are not being regularly serviced and 15% do not have a back-up unit or even a spare battery. Radio-controlled units can be found on a wide range of machinery in the marine industry, from deck cranes to rope winches and reach stackers. * * * Homeland Integrated Offshore Services Limited is expecting delivery in December of Guardian 2, its second Damen Fast Crew Supplier 3307 Patrol, just 18 months after a sister vessel entered service. Established in 2006, HIOSL serves the Nigerian oil and gas industry with a range of maritime, security and logistics services. The Lagos headquartered company plans to become the leading marine logistics provider in the Nigerian offshore industry. * * * The US Energy Information Administration (EIA) estimates that Qatar earned $38 billion from net oil exports in 2014. Qatar is the largest exporter of liquefied natural gas (LNG) in the world, and the country’s exports of LNG, crude oil and petroleum products provide a significant portion of government revenues. According to the Qatar National Bank, earnings from the hydrocarbon sector accounted for 49% of its total government revenues in 2014.

Oil price slump hits BP quarterly profits

five new blocks in the UK North Sea. In October it was announced that, subject to government approval, BP was also awarded three shallow water blocks in the Mediterranean Sea off Egypt. The Woodside-operated Western Flank A project offshore Western Australia, the latest phase of the North West Shelf development, began production in October. A charge of $426 million for the Deepwater Horizon oil spill was taken in the quarter, bringing the total cost up to $55.0 billion. BP is selling assets to help finance these charges, and expects to divest $10 billion this year, and another $3bn-$5bn in 2016. “BP has successfully adapted to changing circumstances many times in its history and, in a hard time for the entire industry, I believe we will once again successfully take on today’s challenges,” said chief executive Bob Dudley. “We are already in action, with a quality portfolio and clear plans for the future, underpinned by enduring principles. I am confident BP will continue to deliver value into the years and decades ahead.”

eporting its results for the third quarter of 2015, BP has set out a medium-term financial frame to balance cash flows by 2017 at around $60 per barrel. BP reported replacement cost profit for the quarter ending 30 September at $1.23 billion (£802m), compared with $2.38 billion a year earlier (a standard measure used in the oil industry that takes into account the price of oil). Underlying replacement cost profit (adjusted for non-operational items) was $1.8 billion for the quarter, compared with $1.3 billion for the previous quarter and $3.0 billion for the third quarter of 2014. Total revenue fell to $55.9bn from $94.8bn a year ago, reflecting the fall in prices. The oil price fell below $50 a barrel in the recent quarter, while it was trading at over $100 for much of the same quarter last year. Capital expenditure has also been hit by the industry slow down. Expectations a year ago for 2015 capital expenditure were $24-26 billion, but BP now expects organic capital expenditure to be closer to $19 billion in 2015. During the quarter BP was awarded

Despite the slump in oil prices, the offshore oil and gas sector remains one of the fastest-growing end-users of the satellite communications market. A new report by Frost & Sullivan expects that market-spend of $357.2 million in 2014 will reach $459.9 million by 2020. “Even during a period of low margins for O&G companies, their consumption of satellite communications services and hardware is stronger than the average adoption across industries,” said Frost & Sullivan space communications industry analyst Peter Finalle. “Decreased oil prices do not affect the communication needs of active offshore ships and vessels that are inaccessible by traditional terrestrial technologies. Moreover, no competing technology has proven as effective at long distances away from cellular and microwave towers.” •

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• News & features

EBH Namibia employees trained in engine repair by Rolls-Royce

our employees of Elgin Brown & Hamer (EBH) Namibia have boosted their skills in marine engine repair after being selected to undergo a training programme by Rolls-Royce. The employees were chosen, along with three Rolls-Royce trainees, to attend a three-week course in the Rolls-Royce engine factory in Bergen, Norway. “Our partnership with Rolls-Royce is of significant strategic importance to EBH Namibia, and the training that our employees have received is invaluable in terms of the transference of globally sought-after skills,” says Hannes Uys, chief executive officer of EBH Namibia. “Serving the African market via our Namibian service hub, is a key part of our strategy to provide a good service in every port, every day,” adds

Patrick Adam, Rolls-Royce Service Centre Manager for Africa. “To live up to our own set of high standards we need to invest in our relationship with our partners and invest in our employees. Together with EBH we now have seven engineers trained who will be able to provide all required service and overhaul work on-board our joint customers’ vessels.” EBH Namibia’s HR manager Patrick Chizabulyo describes as the training as “an important milestone” in the mutually beneficial relationship between EBH Namibia and Rolls-Royce. “An important part of our value offering to our customers is to find synergistic partnerships with other players in the industry and to leverage off each other’s expertise. The training that our employees received will enable them to assist our partners, Rolls-Royce, in the

repair and overhaul of Bergen engines, and will also enhance our own skills base at EBH Namibia,” he says. Based on an agreement which was signed in early 2011, Rolls-Royce, under its marine division Marine & Industrial Power Systems (MIPS), has been operating a dedicated servicing hub at EBH Namibia’s Walvis Bay facility. EBH Namibia has been providing artisanal and semi-skilled labour, working alongside Rolls-Royce technicians in propulsion and related mechanical work. The newly-acquired skills will enhance Rolls-Royce and EBH Namibia’s position to tender for Bergen overhaul work in the future. Bergen Engines, a subsidiary of RollsRoyce Power Systems, manufactures a range of medium speed gas and liquid fuel engines for the marine and offshore oil and gas industries.

Datum360, a UK Software as a Service (SaaS) provider based in Teesside, has partnered with Houston, Texasbased PerfectProjects Inc, to market its engineering management solutions to process industries in the North American market. This is the third partnership to be announced in the space of a month after Datum360 signed agreements with two leading Malaysian companies - EDMS Consultants and Horizon 3 – both

highly reputable providers in the Asia Pacific region. Delivering class libraries to four of the six Supermajor oil companies, Datum360 has built a reputation in the industry for implementing robust engineering information management systems at the start of major asset intensive programmes. “The time is right for the company to expand our portfolio,” said Hans van der Drift, CEO of PerfectProjects.

“Our heritage has focused on providing recovery to distressed projects. Working alongside Datum360 will allow us to offer our clients the opportunity to implement engineering information management systems from the off-set of projects so they can achieve their desired outcome and as such, reduce the need for salvage operations further down the line as a result of failure to implement robust systems.” •

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• News & features

Kootenay’s Cervantes project optioned to Aztec Metals

Indonesia rejoining OPEC despite being net importer of petroleum

he US Energy Information Administration (EIA) reports that the Organization of the Petroleum Exporting Countries (OPEC) has notified Indonesia that it plans to accept the country’s request to reactivate its membership at the next OPEC meeting in December. Once it rejoins, Indonesia will regain its status as the only Asian member of OPEC and the only member that is a net importer of petroleum and other liquids. OPEC, founded in 1960, currently has 12 members, but membership has always been fluid—Ecuador suspended its membership in 1992 and rejoined in 2007; Gabon joined in 1975 and terminated its membership in 1995. Indonesia originally joined OPEC in 1962 but suspended its membership at the beginning of 2009. OPEC does allow for associate membership, but currently all 12 members are full members. Indonesia’s decision to suspend its OPEC membership was prompted by growing internal demand for energy, declining crude oil and condensate production in mature fields, and limited investment to increase production capacity. Indonesia had become a net importer of petroleum and other

liquids by 2004 after domestic demand exceeded production, as Indonesia’s production of petroleum and other liquids has been on a general decline since the mid-1990s. Indonesia produced about 790,000 barrels per day (b/d) of crude oil and condensates in 2014, the third-lowest level among OPEC countries. According to OPEC’s statute, the organization allows as a member any country that is a substantial net crude oil exporter, has similar interests to the organization, and is accepted by threefourths of the full members. Although Indonesia is a net oil importer, the country continues to export crude oil and condensates. Because Indonesia is an archipelago, geographic distances between its domestic oil production and demand centers encourage both imports and exports. Despite its growing oil demand, Indonesia’s oil and natural gas sectors continue to be an important part of the country’s economy. Indonesia imports oil products, particularly gasoline, as a result of insufficient refining capacity to meet the growing demand for oil products. Indonesia said that rejoining OPEC

will strengthen its cooperation with oil-producing countries, provide greater access to crude oil supplies, and allow the country to be a link between energy producers and consumers. Indonesia currently buys crude oil and petroleum products through third parties or traders and wants direct access to longterm crude oil supply contracts through negotiations made between the national oil companies of OPEC members. Indonesia anticipates more crude oil imports will be needed to meet domestic demand from refining capacity additions. Indonesia is planning a number of upgrades and expansions to existing refineries slated to become operational within the next decade. Indonesia has also proposed to build four new refineries, each having a capacity of 300,000 b/d. Because Indonesia struggles with the level of investment needed to offset oil and natural gas production declines and a lack of adequate infrastructure, it hopes to attract investment in both its upstream and downstream sectors from OPEC members. Indonesia is currently in discussions with several OPEC countries about crude oil supply deals and investments in refinery projects. •

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• News & features

Grangemouth operator Ineos to acquire North Sea gas fields

n its first venture into upstream oil & gas, Swiss chemical giant Ineos has agreed to purchase all of the UK North Sea gas fields owned by the DEA Group, a German-based oil and gas firm owned by Russian billionaire Mikhail Fridman’s investment company LetterOne Group. The 12 fields, mainly in the southern North Sea, were sold to LetterOne in March 2015 by German firm RWE, but in April the UK government insisted that they be sold again. As sanctions were being tightened against Russia over its involvement in Ukraine, Ed Davey, UK Energy minister prior to the May election, said it was not in the UK’s interests for these fields to be subject to the risk of sanctions, and threatened to revoke the owner’s operating licence if they were not sold by 20 October. A new subsidiary, Ineos Upstream, will acquire the fields which include the Breagh and Clipper South fields in the southern North Sea. The annual production from these fields accounts for 8% of the UK’s annual gas production. The acquisitions are well positioned close to Ineos’ production sites in Scotland and the North East of England. “Ineos has been very open about its intention to make strategic investments in the North Sea and this acquisition is our first step in fulfilling this goal,” said Ineos chairman Jim Ratcliffe. “It will also help our UK petrochemical assets to

have ongoing access to competitive energy.” Ineos operates Scotland’s largest manufacturing complex at Grangemouth which is the only refining/ petrochemicals complex directly attached to the North Sea. As one of the world’s largest operators of chemical plants and a huge consumer of hydrocarbons these assets are expected to make a significant contribution to Ineos’s European energy and feedstock strategy. “Ineos and its JV partners are huge consumers of natural gas, ethane, propane and condensates,” said Rob Nevin, chairman of Ineos Upstream. “North Sea oil and gas can make a significant contribution to providing these feedstocks as well as servicing our energy needs.” “The acquisition of these North Sea gas fields is a great entry point for the Ineos Upstream business,” added Ratcliffe. “They are high quality, low risk assets and they come with a highly experienced management team. Whilst no decisions have yet been made, we will continue to evaluate other opportunities in the North Sea.” The transaction is subject to competition clearance from the European Commission, but Ineos does not foresee any major issues with receiving this clearance, and is hoping for a completion date in later this year. The existing management team at DEA’s UK business will stay in place and run the business post-completion.

•

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• News & features

Balltec Engineered Solutions lifts gas compression facility

he installation of the world’s first underwater gas compression plant, Åsgard, has been achieved in a collaboration involving Statoil, Aker Solutions and Balltec Engineered Solutions. Balltec’s lifting technology is now helping to establish a fully functioning subsea gas production and processing system at a depth of 300 metres. The module designers, Aker Solutions, chose Balltec to develop the lifting system based on the company’s experience and track record of engineering innovation in heavy lift systems in deep-water. The Balltec lifting solution was used for the deployment of five different subsea module designs of various differing weights and sizes. Balltec’s scope of work was to design a flexible connector solution able to pick up the modules and land them on the seabed.

The connectors were designed as part of an engineered lift and were used to connect the modules and a lifting frame to accommodate the complex load parameters. “When Aker Solutions approached Balltec to design a lifting solution, the module design parameters had already been set,” said Marco Teixeira, Balltec technical director. “This meant that our system had to be flexible enough to adapt to the existing designs but robust enough to cope with the extremely difficult load conditions.” The Balltec lifting solution is part of the LiftLOK™ family of connectors and incorporates new design principles not previously seen in Balltec products. This version of the LiftLOK, now DNV approved, is a purely mechanical system that does not require any manual or remote intervention during connection

and is designed to be tolerant to substantial negative and side loads. The total scope of work for Balltec was the design and supply of 58 male connectors and 12 female connectors and also included the design and manufacture of two custom test rigs. Following the success of the initial five lifting systems, Balltec was contracted to provide a completely different lifting solution for the sixth and final module. “Balltec successfully designed, manufactured and tested an entirely new lifting system within four months from receipt of order, meeting the client’s demanding technical and schedule requirements, including certification under the new DNV rules for lifting,” said managing director Russell Benson. “We are now pleased to report that the LiftLOK system has been used and the modules are now installed subsea.”

LNG shipping freight rates continue to be under pressure from weak Asian demand and a growing fleet. Shipowners are now pinning hopes on a revival in European demand. However, European LNG demand growth will not be sufficient to raise freight rates, according to the newly launched LNG Forecaster report published by global shipping

consultancy Drewry. Until the recent fall in oil prices, Asian LNG prices were at a premium compared to piped gas prices in Europe. European traders therefore preferred to re-export cargoes to more profitable Asian markets. This helped to create substantial shipping demand as vessels found employment on both legs of the trade, first in import and

then in re-export. However, as Asian demand has weakened, the price differential between Asian LNG and European piped gas has eroded, which has hit re-exports from Europe. Spain, the biggest re-exporter from Europe, shipped 1.3 million tonnes of LNG during the first eight months of the current year, down 40% over the same period last year. •

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Maersk Oil:

Developing North Sea Fields Founded in 1962, Maersk Oil looks for long term growth opportunities to fulfil its ambition to become a top-five producer in the North Sea

â&#x20AC;˘

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“Maersk Oil and partners’ £3 billion investment to develop the Culzean discovery is excellent news for the UK”

•

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• Maersk Oil

n August this year Danish giant Maersk Oil was given the go ahead by the UK Oil & Gas Authority for the high pressure, high temperature (HPHT) Culzean field in the North Sea. The UK approval is an important milestone in the Culzean project, which is part of Maersk Oil’s ambition to become a top-five producer in the North Sea. Discovered in 2008 by Maersk Oil and its co-venturers, including JX Nippon, the gas condensate field has resources estimated at 250300 million barrels of oil equivalent.

Maersk Oil is looking for new long-term growth opportunities in the North Sea, investing heavily in projects and improving the efficiency of operations. Culzean is a natural gas field, which helps diversify the company’s oildominated portfolio. Production is expected to start in 2019 and continue for at least 13 years, with plateau production of 60,000-90,000 boe per day. It is the largest gas field sanctioned by the UK since East Brae in 1990, according to consultancy Wood Mackenzie. “Culzean is an important development for the UK and also for Maersk Oil and our co-venturers. We are pleased the field will support UK economic growth as well as extend understanding of HPHT development,” said Maersk Oil CEO Jakob Thomasen. “Culzean is the latest in a series of large investments by Maersk Oil in Denmark, Norway and the UK – reflecting our commitment to the future of the North Sea region and diversifying Maersk Oil’s portfolio.”

Culzean

Maersk Oil and its co-venturers are investing around £3 billion in the Culzean development, with more than 50% committed to industrial investment in the UK. Over the projected life of the field, it is anticipated that £2.1billion in operating expenditure will also be spent in the UK domestic market. The field supports the UK’s transition to gas-fired electricity generation and is expected to support 6,000 UK jobs, and create more than 400 direct jobs. The project benefits from the UK’s HPHT Cluster Area Allowance that supports the development of such projects – which typically have considerably higher capital costs – and encourages exploration and appraisal activity in the surrounding area. Maersk Oil UK is the operator of Culzean, with JX Nippon Exploration & Production (UK) Limited and BP (Britoil Ltd) its co-venturers. The field is located around 145 miles east of Aberdeen. Challenges associated with developing the Culzean reservoirs include temperatures of up to 175 degrees centigrade and high pressure that is equivalent to being 9 kilometres underwater, requiring specialised equipment that can handle the extreme conditions. This makes the project more capital intensive, hence the expected huge total investment of about £3 billion, of which Maersk Oil’s share is about half. The North Sea region has an estimated potential of 26–38 billion barrels yet to be discovered, according to national oil agencies, and it remains a technically attractive province for future development, provided costs and regulatory regimes continue to attract investment. Maersk Oil has a share in Johan Sverdrup, one of Norway’s largest ever discoveries, and in the UK’s Golden Eagle, which started production in

2014. The Tyra Southeast expansion in Denmark has added production from a current asset. At plateau production, Culzean and these other projects will add about 90,000 boe/pd to Maersk Oil’s entitlement production. “Sanction of this landmark project represents a major achievement and an exciting milestone for Maersk Oil UK,” said Morten Kelstrup, Maersk Oil UK managing director. Andy Samuel, chief executive of the Oil & Gas Authority, said: “Maersk Oil and partners’ £3bn investment to develop the Culzean discovery is excellent news for the UK during a period when the decline in global oil prices has created difficult operating conditions for this critical sector of our economy.”

Johan Sverdrup

Culzean isn’t the only project Maersk Oil is investing heavily in. There is the ongoing development of the Norwegian field Johan Sverdrup, in which Maersk Oil is a partner. Johan Sverdrup is one of the five largest fields in Norway. In August this year the partners in the Johan Sverdrup development received the final approval from the Norwegian Ministry of Petroleum and Energy (MPE), of the plan for development and operation (PDO) for Phase 1 of Johan Sverdrup. “We are proud to be part of the Johan Sverdrup partnership and see this project as a strong contributor to our overall North Sea portfolio of operations and developments over the coming years. The project is the biggest planned investment in the entire North Sea basin over the coming decade, illustrating that the basin still holds significant potential,” says Maersk CEO, Thomasen. “With more than 50 years’ experience in the North Sea, Maersk Oil has a strong pedigree participating in phased developments similar to the Johan Sverdrup project. By applying the right technologies and capabilities, this important project will provide a significant contribution to Norwegian society for decades,” says Neil Cummine, managing director of Maersk Oil Norway. Phase 1 of the Johan Sverdrup development, with an estimated capital expenditure of NOK 117 billion, consists of four bridge-linked platforms and three subsea water injection templates, and has a production capacity of 315,000-380,000 barrels of oil equivalent per day. First oil is planned for late 2019 and the expected recoverable resources are projected to be between 1.4 – 2.4 billion barrels of oil equivalent. By approving the Unit Operating Agreement, the Norwegian Ministry of Petroleum and Energy has ruled the apportionment of the Johan Sverdrup field between the partners. For the full field development, capital expenditure is estimated at approximately NOK 170-220 billion (2015 •

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“Johan Sverdrup is the biggest planned investment in the entire North Sea basin over the coming decade”

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• Maersk Oil

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“The Tyra Southeast extension is a great example of how we extract value from the Danish North Sea by combining intricate knowledge, long-term investments and the right technical capabilities”

value) with recoverable resources of between 1.7 and 3.0 billion barrels of oil equivalent and an expected plateau production of 550,000 to 650,000 barrels per day. The Maersk Oil share of the capital expenditure for phase 1 is US$1.8 billion.

Tyra Southeast

In April this year production started from the new unmanned platform Tyra Southeast-B. The platform is expected to add reserves of 50 million boe over the next 30 years to Danish production. “The Tyra Southeast extension is a great example of how we extract value from the Danish North Sea by combining intricate knowledge, long-term investments and the right technical capabilities,” said Thomasen. “Over the next three decades, the new platform will add both oil and gas to our production. This is an important step in Maersk Oil’s growth journey and it demonstrates that Denmark 26

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continues to be a core area for us.” The drilling of the first well commenced in December 2014 from the Ensco 72 drilling rig. From this well alone the production is expected to be 2,600 boe/pd. The plan is to drill a total of 8-12 horizontal wells during 2015-2017 with each well being about six kilometres long. “We are excited to see first production which will contribute positively to Maersk Oil’s total volumes,” said Martin Rune Pedersen, managing director of Maersk Oil Danish Business Unit, the operator of the Danish Underground Consortium. “The initial planning began four years ago, culminating with the final construction and installation mid-2014. In total, the Danish Underground Consortium has invested DKK 4.5 billion and it is exactly such investments that are needed to secure the future of Danish oil and gas production.” The new platform, located 220 kilometres off Denmark’s west coast, will produce a mixture of oil and gas and is expected to deliver approximately 20 million barrels of oil and 170 billion

• Maersk Oil

standard cubic feet of gas, combined reserves and resources of 50 million boe, with peak production in 2017 of 20,000 boe/ pd. The total investment in the Tyra Southeast expansion of DKK 4.5 billion includes the platform with a total weight of 4,700 tonnes, pipelines and drilling of the wells. With 3,200 employees, turning marginal and challenging fields into commercial successes has been the cornerstone of Maersk Oil’s business since the company was founded in 1962. Maersk Oil developed groundbreaking technologies while working with tight chalk reservoirs in the Danish North Sea and enabled Denmark to become an oil and gas producing country. Later, the company deployed these technologies abroad and became an international player in the upstream business. Today, Maersk Oil operates some 625,000 barrels of oil equivalent per day, with production in Denmark, the UK, Qatar, Algeria, Brazil and Kazakhstan. Exploration activities are ongoing in Angola, Norway, Greenland, Kurdistan, the US Gulf of Mexico and in the

producing countries. There is still huge potential value in the North Sea, and Maersk Oil aims to become a top-five producer, from its current rank of ninth. Projects like Culzean, Tyra SE and Johan Sverdrup showcase the opportunities. As part of its long-term focus, the Maersk Group is working to develop sustainable solutions in all its businesses. It has taken significant steps in recent years to become an industry leader with regard to the environment, including substantial reductions in CO2 emissions. It is strongly committed to the safety of its people. In spite of difficult market conditions, Maersk Group aims for long-term profitable growth, combining focused innovation, a performance-based culture and a philosophy of constant care, to build and maintain leading positions in attractive industries and growth market.

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ÂŠ DORIS Engineering/ F. Lucazeau

years

1965-2015

providing INNOVATIVE DESIGN & QUALITY SERVICES

Looking forward to the next 50 years

www.doris-engineering.com

• Interview

Interview: Masamichi Morooka, Chairman, International Chamber of Shipping

asamichi Morooka has been in the shipping industry for over 40 years. His current role with ICS requires finding the right balance between the members he represents and regulatory bodies and governments. What is your greatest achievement as chairman of the ICS? ICS rarely shouts about its achievements. Quiet efficiency is more the ICS style. Any success we have in persuading governments to take more account of the industry’s views is really due to the collective efforts of our member national shipowners’ associations, both in developing practical ICS policy positions and in encouraging their respective governments to listen to the ICS point of view. But during my time as chairman, I do think we have had some success in getting governments to finally understand the serious problems associated with the IMO Ballast Water Convention, especially the flaws in the IMO type-approval process for the really expensive treatment systems that shipowners will soon be required to fit. Following a high-profile campaign, IMO agreed to adopt a resolution last year which commits governments to resolving the problems raised by ICS, so that the Convention will hopefully be fit for purpose when it finally enters force.

Unfortunately, the different regime being applied in the United States is complicating things even further and making global implementation even more chaotic. The US ballast water regime is already in force, but the US has still not yet approved any treatment systems that shipowners can install with confidence. This is also delaying entry into force of the IMO ballast regime, because governments that have not ratified the IMO Convention will probably remain reluctant to do so until this mess in the US is sorted out. How did your experience in the shipping industry prepare you for your current role? Through my many years in shipping, I have developed a deep appreciation of the need for shipping to be governed by an international regulatory framework. We are a global industry and without global rules we have chaos. For an individual company, unilateral regulation, whether regional, national or local, can create big problems, affecting the efficiency of operations and a shipowner’s ability to compete fairly in international markets. First-hand experience of this has provided a solid foundation for my role as chairman of ICS, which strives everyday to promote the global regulation of the shipping industry. On a more practical level, I have previously spent a great deal of time working in the liner shipping sector, where I regularly attended consortia negotiations with shipping companies

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“We are a global industry and without global rules we have chaos”

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• Interview based in other nations. Through this process, I think I learned how to manage and conclude debates effectively and how to reconcile differences of opinion in order to reach consensus between different parties. This has also been very helpful when overseeing the adoption of ICS policy positions by our board, which has to balance the interests of the different national associations. What has been your most challenging moment? I’m not sure that any one ‘moment’ stands out, but there have certainly been overarching challenges that have been particularly prominent. One of these has been addressing how the shipping industry’s CO2 emissions should be further regulated. There is immense pressure on governments to develop CO2 reduction measures for application to shipping, in addition to those technical and operational regimes already adopted by IMO. Engaging with governments to ensure that any further regulation is only developed at IMO for global application, and is proportionate to shipping’s contribution to the world’s CO2 emissions, is an enduring challenge for ICS. How concerned is the ICS with environmental protection? Safety of life at sea must always be our greatest priority, but the protection of the marine environment is a very close second and it is actually environmental issues that take up most of ICS’s time, because this is what dominates the agenda of our regulators such as IMO. For the past 40 years, ICS has been influential in the development of the MARPOL Convention and its Annexes, which comprehensively regulate all aspects of environmental performance from garbage management to sulphur emissions and CO2, not forgetting the need to prevent oil pollution. ICS has also participated in the development of the IMO Civil Liability Conventions covering compensation from oil spills, the Ballast Convention (as we have already discussed) as well as the Hong Kong Ship Recycling Convention and things like the IMO Polar Code. ICS works hard to raise awareness of these regulations throughout the industry and develops practical guidance on how they can best be implemented. We continue to witness mass migrations in unsafe craft in the Mediterranean Sea. In your view, what is the solution? Shipowners and their crews have been deeply affected by this crisis, and merchant ships have already assisted with the rescue of over 65,000 people. There are, of course, no easy solutions. The root causes are political and probably beyond our capacity to influence. But ICS has continued to press governments to dedicate additional search and rescue resources to the region, so as to prevent an over-reliance on merchant vessels to conduct large scale rescues. Coming to the aid of anyone in distress at sea is a deeply held maritime tradition, as well as an obligation under international law. But merchant vessels and crews are not best equipped to conduct these large scale rescues of hundreds of people at a time, nor should they be expected to be. The crews onboard our ships are seafarers, not search and rescue professionals. Something which is often overlooked is the impact of these rescues on our crews.

Piracy continues to be a global threat. How can this be reduced? Piracy is indeed a global threat, and we are currently witnessing high levels of activity in West Africa and South East Asia. There are important differences in the forms piracy can take in different regions, and the solutions that work in one area may not be applicable to another, but generally speaking, the reduction in the incidents off the coast of Somalia and in the Indian Ocean in recent years would seem to underline the importance of a multi-dimensional approach to tackling piracy. The compliance by the industry with its own best management practices on preventing attack, together with the deployment of naval forces in the region, have led to a dramatic reduction in the number of attacks. That said, we cannot rest on our laurels and the possibility of a resurgence in Somali pirate activity cannot be written off. What stresses do you think the shipping industry will face over the next 12/24 months? In economic terms, it appears that the shipping industry will continue to face a difficult demand/supply imbalance, with slowdown in world trade as a result of continuing problems in the Eurozone and the economic slowdown in China dampening demand for shipping at a time of continued overcapacity in most trades. Although, on the whole, demand does appear to be slowly recovering from the 2008 slowdown, it is doing so at a gradual and varied pace. The challenge of implementing new environmental regulations is one that the industry has faced and will continue to face moving forward. New IMO requirements for the use of low sulphur fuel in emissions control areas came into effect in January this year, and the industry is continuing to adjust to the new regime. Though issues still remain, not least with respect to the parallel regime in the United States, the IMO Ballast Water Management Convention is also expected to enter into force within the next two years. Complying with this new regulation will be a major adjustment for the industry. What is your impression of Gibraltar’s shipping industry? Gibraltar is an exciting maritime hub. The Gibraltar Ship Registry ranks among some of the best performing flags by most assessments, including the ICS Flag State Performance Table, and has done now for many years. The registry’s now attracting tonnage from a range of shipping sectors and owners from a wide spread of geographical locations. As a port, Gibraltar has always been a strategically significant hub, connecting as it does the Atlantic Ocean and the Mediterranean Sea. This is not about to change, and it is good that significant investment is being made into the development of the port’s services and the expansion of its capacity. This mutually beneficial relationship between Gibraltar and the global shipping industry would seem to me to have a very bright future. Paul González-Morgan Editor, Gibraltar Shipping Email: shippinggib@gmail.com Twitter: @ShippingGib Web: www.gibraltar-shipping.com

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Aging personnel The future is now, says Hint CEO Wouter Last, referring to the personnel problems faced by the oil and gas sector

or years we have been talking about the problems the oil & gas and petrochemical industry will be facing in the future: the shortage of personnel and the brain drain that accompanies it. This future is happening now. Companies are already struggling with baby boomers on the verge of retirement and the recruitment of young and skilled technical workers. Because investing in education takes years to be fruitful, we are in need of a different approach. I believe IT solutions play a big part in helping out the industry. The oil and gas workforce is aging. It is even said that, worldwide, half of the oil and gas workforce could retire this year. This is a disaster for our industry. These workers bring years of experience and tons of knowledge to the table. Younger generations lack skills and expertise, something we can’t blame them for. Development takes time. In the meantime, this leaves companies with a huge brain drain. But the issue knows two sides. Workers are aging and therefore retiring, yet on the other side – that of employee inflow – figures aren’t looking good either. The industry is finding it harder and harder to attract new people. Young potentials often choose more seemingly glamorous industries, such as consulting and advisory. They don’t want to get their hands dirty, so to speak. Even though in reality this image does not fit the modern technology-driven industry anymore, it still is associated with hard (physical) work and stained overalls. The sector is trying to motivate the new generations to establish a career in oil and gas, already starting in elementary

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• Aging personnel

school. Governments support this mission and have been launching campaigns to encourage children to choose a technical education. But it takes years to educate new generations of workers. And after that, even more years are

The oil and gas workforce is aging. It is even said that, worldwide, half of the oil and gas workforce could retire this year needed to get them up to the high standards demanded by the industry. In other words: we ran out of time! We need solutions that can solve this puzzle right away. We need to be smart. We have

to be more productive with fewer people. Therefore, efficiency has become one of the industry’s KPIs. I believe IT solutions play a big part in helping out. Monitoring, metering and analyses are the foundations of efficiency in management and production in the oil & gas and petrochemical industry. Process analysers are your eyes and ears in controlling performance. Their applications vary from monitoring and reference to process control, safety, custody transfer, fiscal metering and allocation. Analysers provide essential data. But too often, analysers are more of a burden than a delight on the shop floor for they lack long term measurement stability and are hard to maintain. This is where analyser management comes into play and where personnel shortages are resolved. If done right, IT solutions for managing and maintaining analysers in the field and in the laboratory can reduce the workload of operators and laboratory workers significantly. In addition, maintenance efforts can be reduced. You’ll need less people in the field, running around to check on all instruments and fixing them if necessary. A capable management system will detect errors before a real crisis can occur, without the need for redundant check-ups on installations that are very time consuming. At the same time, plant operability will be improved and availability will increase. In other words: it is possible to do more with less. Fewer resources and especially fewer people. It is time to change our course in solving the scarcity of workers in the oil and gas market. Let IT solutions be your answer. •

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People first Donna Smith examines how your people can influence your brand’s reputation

rand image is everything to a business – it can be essential to its survival. An outsider’s perception of how your company functions and how successful it seems will be a factor to potential new customers and stakeholders alike. At a much higher level, even your share price could depend on your brand’s reputation. While stock market brand bashing is, fortunately, not very common, if you are not in control of everything that might affect your reputation, there is always potential for something to go wrong. As consumers we make choices based on brand reputation every day. From clothing to home insurance our decisions are influenced by a company’s reputation – not to mention their advertising campaigns. If Kevin Bacon chooses EE then it must be good - right? We also make choices subconsciously, based on our friends’ and families’ experience, without realising how much influence they have on us. Our choice of broadband supplier (or another utility) is a good example; before switching to another company we talk to our friends and family about what they think of their supplier. Personal recommendation counts for a lot in choices like this. Many factors influence a brand’s reputation, but one that is often overlooked is the insight into the company you get from the people who work there. When meeting someone for the first time, we often say, “where do you work” or “what do you do” as an ice breaker. What that person says about the

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• People first

company he or she works for can leave a lasting impression. Your people are the face of your company, unconsciously praising (or complaining about) your business to family, friends and acquaintances. What are they saying about you, and what can you do about it? When your people talk to other people, they offer a unique insight into how you run your business – what works well and what doesn’t (in their opinion), how you treat your employees and whether your company is a good place to work. You don’t get this kind of feedback from internal surveys or questionnaires. In reality, you may never know exactly what anybody says about your company in the pub, but you can influence what they are likely to say by how you treat them on a day to day basis. As well as influencing your company’s reputation, what your people say about your business also reveals a great deal about them. If they publically complain about your company’s failings, what does this say about their loyalty? If they brag about how easy their job is, does this reflect their integrity and work ethic, or is their ‘bad mouthing’ the result of feeling undervalued? It’s all too easy to take people for granted, and all too easy to underestimate the effect this might have on your reputation. What implications might it have on your future recruitment, for instance? Can you fill your vacancies with the best talent available? If you have a reputation as a good employer, the best

people may want to work for you. If you can attract the ‘pick of the bunch’ you will get the skills and attitudes to elevate your brand. A company with a great reputation attracts skilled employees and sends a message to discerning customers (like you and me) who are willing to pay a premium for top quality goods and services. Organic foods are a great example; they are more expensive but sell well because people believe in their reputation as healthy alternatives. We pay more, because we believe in the brand. Recognising individual contributions and appreciating your people will help your employees create a positive reputation for the company. Ensuring your people feel like a valued part of your company can also provide a platform for them to give constructive feedback, and enable them to play a key role in any improvements that result from it. Behind every successful company is a great workforce. Teams of people working together to deliver to the highest quality against agreed deadlines and costs. Are you doing all you can to help your people influence your brand’s reputation for the better? Donna Smith is a project manager for Hewlett Packard. She has worked in the IT service industry since 1999, undertaking a number of management roles including change manager and resource & reporting manager. •

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Mercy Ships: British second officer navigates floating hospital

The world’s largest charity hospital ship, the Africa Mercy, is staffed by more than 400 volunteers at any one time

imon Purvis is not just your average seafarer – he volunteers on a floating hospital which delivers free and vital medical care to some of the poorest countries in the world. At the tender age of 26, South Shields resident Simon takes time out of his busy work schedule to serve as the Second Officer on board the Africa Mercy, operated by international hospital ship charity Mercy Ships. Simon began volunteering with Mercy Ships in 2014 while the ship was docked in the Republic of Congo and returned at the start of 2015 when the ship was on an eight month outreach in Madagascar. This summer Simon returned for a third time, helping to successfully navigate the ship from Durban to Madagascar where the floating hospital has docked again for another field service. He will remain on board until the end of November. Reflecting on his time on the floating hospital, Simon said: “The most rewarding aspect of my role is training our African 40

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“You see sights and experience things which move you to compassion”

• Mercy Ships rewarding. I’ve had the opportunity to sail the seas to serve the vulnerable and the poor who are in desperate need of help. You see sights and experience things which move you to compassion,” Simon continued. “I became a seafarer to see the world, but I could never have imagined that my career could open me up to experiences like volunteering with Mercy Ships. I feel a great sense of purpose

in serving as part of an organisation where we prioritise loving our neighbour, helping and caring for others.” Judy Polkinhorn, executive director of Mercy Ships UK, said: “The ship, the Africa Mercy, acts as both hospital and home to many of our volunteers. Without it we wouldn’t be able to provide the level of care and reach those people who need help the most.

crew members, particularly our deck hands and deck ratings who are working towards becoming professional seafarers at the rank of deck able seafarer. “We are very passionate about training and African development here at Mercy Ships, and I feel extremely privileged to play a part in the progress of other seafarer’s careers, particularly those who may not have had the opportunities that I had growing up.” As the Second Officer on the Africa Mercy, Simon is in charge of all matters concerning safety and training. This involves keeping a navigation watch on the bridge when the vessel is at sea, taking charge of line handling operations when entering and leaving port, planning and organising various drills and training exercises for emergency teams, making regular safety rounds of the vessel and chairing the on board safety committee, among other duties. “Volunteering for such a unique charity is extremely

“While the deck and engineering team does not work directly with the patients who receive free medical treatment on the ship, they are vital to the running of the floating hospital and without them the ship would not function. We are extremely grateful to all the volunteers that give up their time and offer support for Mercy Ships.” Founded in 1978, Mercy Ships has worked in more than 70 countries providing services valued at more than £750 million, helping in excess of 2.5 million people. * * *

For more information on Mercy Ships please visit www.mercyships.org.uk

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onstruction or preliminary work has begun on three new pipelines designed to flow new supplies of natural gas from Azerbaijan to consumers in Turkey, Bulgaria, Greece and Italy. For more than a decade, companies have been announcing proposals to build new natural gas pipelines to connect natural gas resources in Russia, Central Asia and the Middle East with consumers in southern Europe. In contrast to the three new pipelines considered in this article by the US Energy Information Administration (EIA), however, most of these projects have failed to advance. These three new or expanded pipelines would reach from Azerbaijan’s eastern edge on the Caspian Sea to Italy’s southeastern shore. The South Caucasus Pipeline Expansion (SCPX), from Azerbaijan to the Georgia-Turkey border, began construction in Azerbaijan at the end of June. The Trans-Anatolian Natural Gas Pipeline (TANAP), from the Georgia-Turkey border to the Turkey-Greece border, officially started construction in March 2015, and the Trans Adriatic Pipeline (TAP), from the Turkey-Greece border to Italy, plans to start construction in 2016. SCPX and TANAP are scheduled to start operations by 2019 42

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and TAP by 2020. Turkey and Italy have contracts to receive 0.6 billion cubic feet per day (bcf/d) and 0.8 bcf/d

These three new or expanded pipelines would reach from Azerbaijan’s eastern edge on the Caspian Sea to Italy’s southeastern shore of natural gas, respectively, while Greece and Bulgaria each are contracted to take 0.1 bcf/d.

• Gas pipeline projects

New pipeline projects

Natural gas pipelines to connect Azerbaijan to southern Europe There have been a number of other proposals for pipelines into Turkey and from Turkey into Europe over the past 10 to 15 years, many of which have been cancelled or are otherwise on hold. The Nabucco pipeline project, which was planned to flow natural gas through southeastern Europe to connect with existing natural gas pipelines in or near Austria, was abandoned in 2013. The South Stream pipeline, proposed to carry gas out of Russia and into Bulgaria and eastern Europe, was at one point about to begin construction, but was delayed by disagreements with the European Union (EU) over EU natural gas and electricity market legislation. Discussions to restart the project stalled after Russia’s involvement in Crimea, and in December 2014 Russian President Putin cancelled the South Stream project. The Turkish Stream pipeline project was announced at the same time as the South Stream pipeline cancelation. The proposed Turkish Stream pipeline, backed by Russia’s majority state-owned natural gas company Gazprom, would have the same capacity to transport natural gas from Russia across the Black Sea, but it would make landfall in Turkey, which is not an EU member country, instead of Bulgaria, which is an

EU member country. However, Russia and Turkey have been unable to reach a final agreement on the pipeline and, in July 2015, Gazprom cancelled its contract with Saipem, the Italian company contracted to lay the first part of the pipeline. The future of the Turkish Stream pipeline is currently uncertain, but among the more recent pipeline proposals are Russia’s as-yet-unnamed proposed onshore extension of the Turkish Stream pipeline, which would take natural gas across Greece before heading north to Austria. Other potential pipelines include a proposal to build a bidirectional pipeline called Eastring from Slovakia, through Hungary and Romania, connecting to Turkey through the existing Trans-Balkan pipeline. Future possibilities for moving natural gas to Turkey and Europe also involve natural gas exports from Iran and Iraq. The lifting of sanctions on Iran would allow European countries to import gas from Iran. Although Iran already exports natural gas to Turkey, it has long had plans to export larger volumes of natural gas through Turkey to Europe. However, other hurdles would remain, including agreeing on a natural gas price and meeting Iran’s growing domestic demands for natural gas, especially for enhanced oil recovery, power generation, and winter heating. •

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Transforming wasted energy into LNG In recent years, the demand for LNG throughout the world has increased. This demand is driven by many factors, such as cost benefit, emissions requirements and increasing demand for energy. One sector in particular, small scale LNG, is evolving rapidly, driven by the increasing demand for LNG fueled vehicles, localized energy production and virtual gas pipelines. As the small scale LNG market increases, new supply chain technologies must be developed to ensure adequate, cost effective supply of LNG. These new supply chain technologies differ greatly from the traditional large-scale liquefaction, distribution and regasification technologies that have been prevalent over the last few decades. â&#x20AC;˘

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erhaps the most important part of the cryogenic liquid expanders in small scale liquefaction facilities to reduce boil off gas production and increase overall liquefaction small-scale LNG supply chain is the process efficiency. liquefaction facility. Large-scale LNG Liquefaction process liquefaction plants must be geographically order to understand the benefits of cryogenic liquid turbines located near very large natural gas reserves In in the LNG liquefaction process, we must first understand the and sea ports capable of handling large basic process of gas liquefaction. As previously stated, many thermodynamic processes are used to achieve liquefaction LNG carriers, but small scale liquefaction of gasses, however closed loop refrigeration cycles are most facilities can be located virtually anywhere common. Figure 1 shows a simplified liquefaction process using a closed loop, mixed refrigerant cycle. This process consists a small gas source is available due to their of natural gas and mixed refrigerant gas compressors, a heat small modular design. These small-scale exchanger, an evaporative cooler and Joule-Thompson valves. liquefiers use similar processes as large-scale In this process, a refrigerant (typically propane, or a mixture of hydrocarbon gasses) is compressed to a state above its critical liquefaction facilities, but at a much lower pressure. The flow is then passed through a cooler which rejects production rate. the heat of compression to the atmosphere at a near constant

pressure. From there the flow is routed through a main heat exchanger, where it is cooled further. Next, the high-pressure Small-scale liquefiers typically operate in the range of .16 to 966 tonnes (1,000 to 600,000 gallons) per day, compared to their large refrigerant is flashed over a JT valve in an isenthalpic expansion that lowers its pressure to near atmospheric, and reduces its scale counterparts which can produce upwards of 19,600 tonnes temperature. This cold, atmospheric pressure refrigerant is then (12 million gallons) of LNG per day. Various thermodynamic cycles are used in LNG liquefaction, including mixed refrigerant, discharged into the main heat exchanger, where the cycle then repeats. cascade, pre-cooled Joule-Thomson and nitrogen refrigeration. The open loop part of this process that creates the LNG is much Although there are significant differences in these technologies simpler. This process consists of compressing clean, dry methane in terms of capital cost and operating efficiency, they all share to a pressure above its critical pressure, cooling the stream in the common process of expanding high pressure, sub-cooled the main heat exchanger, then expanding the fluid through a LNG to near atmospheric pressure, saturated LNG. Large-scale liquefaction plants generally use near isentropic cryogenic liquid Joule-Thomson valve to near atmospheric pressure. This process results in a liquid/vapor mixture, which is then separated. The expanders to perform this pressure reduction, while small-scale liquid portion, LNG, is sent to storage while the vapor portion is liquefiers use almost exclusively isenthalpic Joule-Thomson recycled back to the gas compressor inlet. valves. This article highlights the benefits of applying isentropic 46

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• Ebara

Figure 1

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Expander basics

Expanders have been traditionally used to generate work by converting a fluidâ&#x20AC;&#x2122;s internal and kinetic energy into shaft torque. This shaft torque is then used to drive a mechanical process or an electric generator to produce power. In LNG plants, however, their use provides even more benefits. When high pressure LNG is flashed across a Joule-Thomson valve, no work is produced. This means that the energy of the fluid before and after the expansion is equal, or isenthalpic. When this same high pressure LNG stream is expanded across a cryogenic expander instead, the energy of the fluid is reduced. Under ideal conditions this expansion is nearly reversible (in thermodynamic terms), resulting in an isentropic expansion. Because the enthalpy of the fluid is reduced, the resulting outlet temperature of the LNG is colder. The colder LNG has a lower vapor quality, resulting in less boil-off gas downstream. The amount of shaft power produced by a cryogenic expander 48

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can be directly related to the amount of boil off gas reduction. This relationship is given by comparing the work output of the shaft in terms of kJ/s (kW), and the enthalpy of vaporization (or latent heat of vaporization) of LNG. For example: đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018; Â đ??&#x201A;đ??&#x201A;đ??&#x201A;đ??&#x201A;đ??&#x201A;đ??&#x201A;đ??&#x201A;đ??&#x201A;đ??&#x201A;đ??&#x201A;đ??&#x201A;đ??&#x201A;đ??&#x201A;đ??&#x201A;đ??&#x201A;đ??&#x201A; Â Where:

đ??&#x2013;đ??&#x2013; đ??¤đ??¤đ??¤đ??¤ đ??¤đ??¤đ??¤đ??¤ = đ??¤đ??¤đ??¤đ??¤ đ??Źđ??Ź đ??Ąđ??Ąđ??&#x;đ??&#x;đ??&#x;đ??&#x; đ??¤đ??¤đ??¤đ??¤

đ??&#x2013;đ??&#x2013; = đ??&#x2013;đ??&#x2013;đ??&#x2013;đ??&#x2013;đ??&#x2013;đ??&#x2013;đ??&#x2013;đ??&#x2013; đ??Ąđ??Ąđ??&#x;đ??&#x;đ??&#x;đ??&#x; = đ??&#x201E;đ??&#x201E;đ??&#x201E;đ??&#x201E;đ??&#x201E;đ??&#x201E;đ??&#x201E;đ??&#x201E;đ??&#x201E;đ??&#x201E;đ??&#x201E;đ??&#x201E;đ??&#x201E;đ??&#x201E;đ??&#x201E;đ??&#x201E; Â đ??¨đ??¨đ??¨đ??¨ Â đ??&#x2022;đ??&#x2022;đ??&#x2022;đ??&#x2022;đ??&#x2022;đ??&#x2022;đ??&#x2022;đ??&#x2022;đ??&#x2022;đ??&#x2022;đ??&#x2022;đ??&#x2022;đ??&#x2022;đ??&#x2022;đ??&#x2022;đ??&#x2022;đ??&#x2022;đ??&#x2022;đ??&#x2022;đ??&#x2022;đ??&#x2022;đ??&#x2022;đ??&#x2022;đ??&#x2022;

If we assume the LNG is pure liquefied methane, we know that the enthalpy of vaporization is equal to 511.8

đ??¤đ??¤đ??¤đ??¤

. Inserting this value into equation 1, we get:

đ?&#x;?đ?&#x;? đ??¤đ??¤đ??¤đ??¤ đ??¤đ??¤đ??¤đ??¤ đ??¤đ??¤đ??¤đ??¤ = =. đ?&#x;&#x17D;đ?&#x;&#x17D;đ?&#x;&#x17D;đ?&#x;&#x17D;đ?&#x;&#x17D;đ?&#x;&#x17D;đ?&#x;&#x17D;đ?&#x;&#x17D;đ?&#x;&#x17D;đ?&#x;&#x17D;đ?&#x;&#x17D;đ?&#x;&#x17D; Â đ??¤đ??¤đ??¤đ??¤ đ??Źđ??Ź đ??Źđ??Ź đ?&#x;&#x201C;đ?&#x;&#x201C;đ?&#x;&#x201C;đ?&#x;&#x201C;đ?&#x;&#x201C;đ?&#x;&#x201C;. đ?&#x;&#x2013;đ?&#x;&#x2013; đ??¤đ??¤đ??¤đ??¤

From large scale to small scale

â&#x20AC;˘ Ebara

Historically, the small scale LNG market has operated in a similar manner as the large scale market, where the LNG is sold on a wholesale basis and is used in power generation and other industrial uses. With increasing environmental and financial concerns over the use of other fossil fuels, the small scale LNG market has begun to grow. This new emerging market is taking on a retail sales model where small-scale liquefiers are being constructed to supply individual customers for use as a transportation fuel for LNG powered trucks and marine vessels, local power generation and local industrial use. To support this new demand, new small-scale liquefaction technologies are being developed that produce between 1,000 and 6,000 gallons per day. These facilities are typically small, stand alone plants or may consist of modular components remotely manufactured and assembled on site. Another difference between the large-scale LNG liquefaction market and the small-scale liquefaction market is the gas source. Large-scale liquefaction plants are built near very large gas reserves that are able to support worldwide import demand. Small-scale liquefiers, on the other hand, can be built or assembled in a fraction of the time near any number of small gas sources such as well heads, gas pipelines, stranded gas reserves and landfills.

Capital and operating costs

When comparing the initial capital costs of small-scale liquefaction, the initial capital costs of large-scale liquefaction are orders of magnitude higher than small scale. On the other hand, the cost per LNG gallon capacity per day is significantly lower. This is due to higher operating efficiencies as well as economies of scale. The ongoing operating expenses of these different size plants follow the same principal. Large-scale plants are much more complex and operate at higher flow rates, resulting in high operating costs. These same reasons however result in a much lower cost per gallon of LNG produced.

This value is the reclaimed capacity of boil off gas per kW power produced by the turbine. On an annual basis, this equals around 61.6 tonnes per year. At a liquid density of around 420 kg/m^3 , this equates to around .16 tonnes per day (100 gal/day) of additional LNG production per kW by replacing a Joule-Thomson valve with a cryogenic expander. The following table uses this relationship at several different power outputs to determine the additional production in gallons per day:

To help close this gap of operating cost per gallon of LNG between small and large scale plants, the Joule-Thomson Valves in a small scale liquefaction plant can be replaced by small scale cryogenic expanders. The result of this additional equipment is the reduction of the operating cost per gallon by both increasing its liquefaction capacity in gallons per day, as well as reducing the sum of the electric power consumed by the plant. The following example highlights this benefit by finding the actual reduction in operating costs in a real life, small-scale plant designed to produce 50,000 gallons per day. â&#x20AC;˘

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To simplify the calculations in this example, we will assume that only a single small cryogenic expander is installed in each of the refrigeration and LNG streams. Also, it will be assumed that the LNG stream is pure methane, while the refrigeration stream is pure propane. The following is a table of LNG and refrigerant stream properties:

The first step in calculating the reduction in boil off gas is to calculate the power output expected from the cryogenic expanderâ&#x20AC;&#x2122;s electric generator. This is done using the following equation:

đ??&#x201C;đ??&#x201C;đ??&#x201C;đ??&#x201C;đ??&#x201C;đ??&#x201C;đ??&#x201C;đ??&#x201C;đ??&#x201C;đ??&#x201C;đ??&#x201C;đ??&#x201C;đ??&#x201C;đ??&#x201C; Â đ???đ???đ???đ???đ???đ???đ???đ???đ???đ??? Â đ??&#x17D;đ??&#x17D;đ??&#x17D;đ??&#x17D;đ??&#x17D;đ??&#x17D;đ??&#x17D;đ??&#x17D;đ??&#x17D;đ??&#x17D;đ??&#x17D;đ??&#x17D; Â đ??¤đ??¤đ??¤đ??¤ = Inserting the data above we get:

đ??&#x2039;đ??&#x2039;đ??&#x2039;đ??&#x2039;đ??&#x2039;đ??&#x2039; Â đ??&#x201C;đ??&#x201C;đ??&#x201C;đ??&#x201C;đ??&#x201C;đ??&#x201C;đ??&#x201C;đ??&#x201C;đ??&#x201C;đ??&#x201C;đ??&#x201C;đ??&#x201C;đ??&#x201C;đ??&#x201C; Â đ???đ???đ???đ???đ???đ???đ???đ???đ???đ??? Â đ??&#x17D;đ??&#x17D;đ??&#x17D;đ??&#x17D;đ??&#x17D;đ??&#x17D;đ??&#x17D;đ??&#x17D;đ??&#x17D;đ??&#x17D;đ??&#x17D;đ??&#x17D; Â =

đ?&#x;&#x2022;đ?&#x;&#x2022;. đ?&#x;&#x2013;đ?&#x;&#x2013;đ?&#x;&#x2013;đ?&#x;&#x2013; â&#x2C6;&#x2014; đ?&#x;&#x2018;đ?&#x;&#x2018;đ?&#x;&#x2018;đ?&#x;&#x2018;. đ?&#x;&#x2014;đ?&#x;&#x2014; â&#x2C6;&#x2014;. đ?&#x;&#x2013;đ?&#x;&#x2013;đ?&#x;&#x2013;đ?&#x;&#x2013; = đ?&#x;&#x201C;đ?&#x;&#x201C;. đ?&#x;&#x2019;đ?&#x;&#x2019; Â đ??¤đ??¤đ??¤đ??¤ đ?&#x;&#x2018;đ?&#x;&#x2018;đ?&#x;&#x2018;đ?&#x;&#x2018;

đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018; Â đ??&#x201C;đ??&#x201C;đ??&#x201C;đ??&#x201C;đ??&#x201C;đ??&#x201C;đ??&#x201C;đ??&#x201C;đ??&#x201C;đ??&#x201C;đ??&#x201C;đ??&#x201C;đ??&#x201C;đ??&#x201C; Â đ???đ???đ???đ???đ???đ???đ???đ???đ???đ??? Â đ??&#x17D;đ??&#x17D;đ??&#x17D;đ??&#x17D;đ??&#x17D;đ??&#x17D;đ??&#x17D;đ??&#x17D;đ??&#x17D;đ??&#x17D;đ??&#x17D;đ??&#x17D; Â =

â&#x20AC;˘

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đ??Śđ??Śđ?&#x;&#x2018;đ?&#x;&#x2018; â&#x2C6;&#x2014; â&#x2C6;&#x2020;đ???đ???[đ??&#x203A;đ??&#x203A;đ??&#x203A;đ??&#x203A;đ??&#x203A;đ??&#x203A;] đ??Ąđ??Ąđ??Ąđ??Ą â&#x2C6;&#x2014; đ?&#x203A;&#x2C6;đ?&#x203A;&#x2C6;đ??đ??đ??đ??đ??đ??đ??đ??đ??đ??đ??đ??đ??đ?? đ?&#x;&#x2018;đ?&#x;&#x2018;đ?&#x;&#x2018;đ?&#x;&#x2018;

đ???đ???[

đ?&#x;?đ?&#x;?đ?&#x;?đ?&#x;?. đ?&#x;&#x2018;đ?&#x;&#x2018;đ?&#x;&#x2018;đ?&#x;&#x2018;đ?&#x;&#x2018;đ?&#x;&#x2018; â&#x2C6;&#x2014; đ?&#x;?đ?&#x;?đ?&#x;?đ?&#x;? â&#x2C6;&#x2014;. đ?&#x;&#x2013;đ?&#x;&#x2013;đ?&#x;&#x2013;đ?&#x;&#x2013; = đ?&#x;&#x2022;đ?&#x;&#x2022;. đ?&#x;&#x17D;đ?&#x;&#x17D;đ?&#x;&#x17D;đ?&#x;&#x17D; Â đ??¤đ??¤đ??¤đ??¤ đ?&#x;&#x2018;đ?&#x;&#x2018;đ?&#x;&#x2018;đ?&#x;&#x2018;

â&#x20AC;˘ Ebara So, by installing cryogenic expanders, the total reclaimed LNG in this example is approximately 1,900 gallons per day. When the additional benefit of electrical power reduction within the facility is taken into account, the overall plant efficiency can be improved by around 4%. This results in a direct 4% reduction in operating costs in terms of $/ gallons/day.

New cryogenic expander development

In the late 1990s, Ebara International Corporation, Cryodynamics division, developed the first fully submerged, variable speed, cryogenic expander. This device was designed utilizing over 40 years of cryogenic industry experience, and featured many of the same design philosophies and techniques used in their submerged pump designs. These turbines were designed specifically for large-scale LNG liquefaction plants with power outputs of as high as 2 MW. Over the next 20 years, Ebara continued to improve and expand their turbine technology to include a wide range of capacities and power outputs. Recently, due to the demand for small-scale liquefaction process improvements, Ebara has used their turbine experience to develop the worldâ&#x20AC;&#x2122;s first line of small-scale LNG expanders. These turbines use similar technology as large-scale applications, but on a much smaller scale. Capable of supporting liquefaction plant capacities between 10,000 and 600,000 gallons per day, these turbines are ideal additions to any liquefaction process designer looking to decrease their operating cost per gallon produced.

Conclusion

The next step in calculating the reduction in boil-off gas is to apply the results above together with the enthalpy of vaporization of the LNG and refrigerant into equation 1. This results in:

đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018; Â đ??&#x153;đ??&#x153;đ??&#x153;đ??&#x153;đ??&#x153;đ??&#x153;đ??&#x153;đ??&#x153;đ??&#x153;đ??&#x153;đ??&#x153;đ??&#x153;đ??&#x153;đ??&#x153;đ??&#x153;đ??&#x153; Â đ??&#x;đ??&#x;đ??&#x;đ??&#x;đ??&#x;đ??&#x;đ??&#x;đ??&#x; Â đ??&#x2039;đ??&#x2039;đ??&#x2039;đ??&#x2039;đ??&#x2039;đ??&#x2039; Â đ??Źđ??Źđ??Źđ??Źđ??Źđ??Źđ??Źđ??Źđ??Źđ??Źđ??Źđ??Ź Â =

Cryogenic expanders have been used for almost two decades in large scale LNG liquefaction plants due to their ability to increase process efficiency. This technology however has yet to be applied to small-scale liquefaction plants. As the previous example shows, by utilizing cryogenic expanders, the operating cost of a small-scale liquefaction plant could be reduced by approximately 4%. This reduction in operating costs typically equates to a payback on the additional capital required to install a turbine between 1 and 4 years, depending on the size of the turbine.

đ?&#x;&#x201C;đ?&#x;&#x201C;. đ?&#x;&#x2019;đ?&#x;&#x2019; đ??¤đ??¤đ??¤đ??¤ đ??¤đ??¤đ??¤đ??¤ =. đ?&#x;&#x17D;đ?&#x;&#x17D;đ?&#x;&#x17D;đ?&#x;&#x17D;đ?&#x;&#x17D;đ?&#x;&#x17D;đ?&#x;&#x17D;đ?&#x;&#x17D; Â đ??¤đ??¤đ??¤đ??¤ đ??Źđ??Ź đ??¤đ??¤đ??¤đ??¤

đ?&#x;&#x201C;đ?&#x;&#x201C;đ?&#x;&#x201C;đ?&#x;&#x201C;đ?&#x;&#x201C;đ?&#x;&#x201C;. đ?&#x;&#x2013;đ?&#x;&#x2013;

đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018;đ??&#x2018; Â đ??&#x153;đ??&#x153;đ??&#x153;đ??&#x153;đ??&#x153;đ??&#x153;đ??&#x153;đ??&#x153;đ??&#x153;đ??&#x153;đ??&#x153;đ??&#x153;đ??&#x153;đ??&#x153;đ??&#x153;đ??&#x153; Â đ??&#x;đ??&#x;đ??&#x;đ??&#x;đ??&#x;đ??&#x;đ??&#x;đ??&#x; Â đ??Ťđ??Ťđ??Ťđ??Ťđ??Ťđ??Ťđ??Ťđ??Ťđ??Ťđ??Ťđ??Ťđ??Ťđ??Ťđ??Ťđ??Ťđ??Ťđ??Ťđ??Ťđ??Ťđ??Ťđ??Ťđ??Ť Â đ??Źđ??Źđ??Źđ??Źđ??Źđ??Źđ??Źđ??Źđ??Źđ??Źđ??Źđ??Ź Â =

đ??¤đ??¤đ??¤đ??¤ đ?&#x;&#x2022;đ?&#x;&#x2022;. đ?&#x;&#x17D;đ?&#x;&#x17D;đ?&#x;&#x17D;đ?&#x;&#x17D; đ??¤đ??¤đ??¤đ??¤ =. đ?&#x;&#x17D;đ?&#x;&#x17D;đ?&#x;&#x17D;đ?&#x;&#x17D;đ?&#x;&#x17D;đ?&#x;&#x17D;đ?&#x;&#x17D;đ?&#x;&#x17D; Â đ??¤đ??¤đ??¤đ??¤ đ??Źđ??Ź đ??¤đ??¤đ??¤đ??¤

đ?&#x;&#x2018;đ?&#x;&#x2018;đ?&#x;&#x2018;đ?&#x;&#x2018;đ?&#x;&#x2018;đ?&#x;&#x2018;. đ?&#x;&#x201D;đ?&#x;&#x201D;đ?&#x;&#x201D;đ?&#x;&#x201D;

These values can then be summed, and converted to gallons per day:

đ??&#x201C;đ??&#x201C;đ??&#x201C;đ??&#x201C;đ??&#x201C;đ??&#x201C;đ??&#x201C;đ??&#x201C;đ??&#x201C;đ??&#x201C; Â đ??Ťđ??Ťđ??Ťđ??Ťđ??Ťđ??Ťđ??Ľđ??Ľđ??&#x161;đ??&#x161;đ??&#x161;đ??&#x161;đ??&#x161;đ??&#x161;đ??&#x161;đ??&#x161;đ??&#x161;đ??&#x161; Â đ??&#x153;đ??&#x153;đ??&#x153;đ??&#x153;đ??&#x153;đ??&#x153;đ??&#x153;đ??&#x153;đ??&#x153;đ??&#x153;đ??&#x153;đ??&#x153;đ??&#x153;đ??&#x153;đ??&#x153;đ??&#x153; =

(. đ?&#x;&#x17D;đ?&#x;&#x17D;đ?&#x;&#x17D;đ?&#x;&#x17D;đ?&#x;&#x17D;đ?&#x;&#x17D;đ?&#x;&#x17D;đ?&#x;&#x17D;

đ??¤đ??¤đ??¤đ??¤ đ??¤đ??¤đ??¤đ??¤ +. đ?&#x;&#x17D;đ?&#x;&#x17D;đ?&#x;&#x17D;đ?&#x;&#x17D;đ?&#x;&#x17D;đ?&#x;&#x17D;đ?&#x;&#x17D;đ?&#x;&#x17D; ) đ??Źđ??Ź â&#x2C6;&#x2014; đ?&#x;?đ?&#x;?đ?&#x;?đ?&#x;?đ?&#x;?đ?&#x;?. đ?&#x;?đ?&#x;?đ?&#x;?đ?&#x;? đ?? đ?? đ?? đ?? đ?? đ?? â&#x2C6;&#x2014; đ?&#x;&#x2013;đ?&#x;&#x2013;đ?&#x;&#x2013;đ?&#x;&#x2013;, đ?&#x;&#x2019;đ?&#x;&#x2019;đ?&#x;&#x2019;đ?&#x;&#x2019;đ?&#x;&#x17D;đ?&#x;&#x17D; đ??Źđ??Źđ??Źđ??Źđ??Źđ??Ź = đ?&#x;?đ?&#x;?, đ?&#x;&#x2013;đ?&#x;&#x2013;đ?&#x;&#x2013;đ?&#x;&#x2013;đ?&#x;&#x2013;đ?&#x;&#x2013; đ?? đ?? đ?? đ?? đ?? đ?? đ??Źđ??Ź đ??¤đ??¤đ??¤đ??¤ đ??Śđ??Śđ?&#x;&#x2018;đ?&#x;&#x2018; đ???đ???đ???đ???đ???đ??? đ???đ???đ???đ???đ???đ??? đ?&#x;&#x2019;đ?&#x;&#x2019;đ?&#x;&#x2019;đ?&#x;&#x2019;đ?&#x;&#x2019;đ?&#x;&#x2019; đ?&#x;&#x2018;đ?&#x;&#x2018; đ??Śđ??Ś

â&#x20AC;˘

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Eni:

A major integrated energy company â&#x20AC;˘

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ounded in Italy in 1953, Eni now operates across the entire energy chain, making continuous efficiency improvements, and developing exploration and marketing activities worldwide

Eni SpA is an integrated company that operates across the entire energy chain, employing more than 84,000 people in 83 countries around the world. Its business strategy is based on operating excellence, and a focus on health, safety and the environment. It is committed to preventing and mitigating operational risks. Eni was founded in 1953 as Ente Nazionale Idrocarburi under the leadership of Enrico Mattei. Enrico was among 54

â&#x20AC;˘

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a small group of industrial leaders who recognized that Italy needed to become a player in global markets and was one of those responsible for transforming Italy from a poor, post-war farming nation into a major industrial force. Eni today is a close, open and dynamic company, holding to its key values of sustainability, culture, partnership, innovation and efficiency, which are communicated across the world by its instantly recognizable symbol, the six-legged dog.

Scope of operations

Eni engages in oil and natural gas exploration, field development and production, as well as in the supply, trading and shipping of natural gas, LNG, electricity, fuels and chemical products. Through refineries and chemical plants, Eni processes crude oil and other oil-based feedstock to produce fuels, lubricants and chemical products that are supplied to wholesalers or through retail networks or distributors.

• Eni

“Eni’s strategy is to pursue organic growth through exploration activities based on a conventional portfolio of titles and a low level of exposure to non-conventional projects” Furthermore, Eni operates in engineering, oilfield services and construction both offshore and onshore, focusing on the execution of technologically advanced mega-projects mainly located in frontier areas. Between 2008 and 2013 Eni discovered resources of 9.5 billion barrels of oil equivalent. In the first nine months of 2014, the company also ascertained the presence of new resources amounting to 700 million boe. This important result is based on a two-pronged upstream strategy: firstly, the pursuit of organic growth through exploration activities based on a conventional portfolio of titles and a low level of exposure to non-conventional projects. Exploration success makes it possible to achieve low discovery unit costs and development projects that are automatically more competitive and, consequently, less susceptible to fluctuations in the price of crude oil. The strategy also foresees the acquisition and maintenance of the role of operator, with a

high level of participation in the most interesting exploration permits. To make exploration performance sustainable Eni is undertaking continuous renewal of the company’s portfolio. In addition, Eni is pursuing the renewal, expansion and diversification of its exploration portfolio, which in recent years has seen the company enter new countries such as South Africa and Myanmar, and the acquisition of new exploration areas in countries like China and Vietnam. By constantly renewing the exploration portfolio Eni is able to spread risk across a range of exploration areas and increase the possibility of discovery. Eni’s current exploration investments are divided across frontier areas, (40% in countries including Mozambique), traditional areas in which the company operates (40% in countries including the Congo and Angola) and in “incremental‘ and “near field‘ exploration projects (20% in countries including Egypt and Pakistan). After two years of exceptional results from “supergiant‘ discoveries in the Rovuma basin in offshore Mozambique, Eni is also achieving important exploration successes. These include oil discoveries in pre-salt layers in West Africa with the discoveries of Nene Marine and Minsala Marine in Congo and gas and condensates at Nyonye Deep in Gabon. These are all discoveries in shallow waters and near to existing infrastructure, which means they can be rapidly brought into production. Also in West Africa, the new discovery of oil in Block 15/06 in Angola; in Egypt, new oil discoveries in the Gulf of Suez and in the Western Desert; in Mozambique, through the delineation of the Agulha field. In Nigeria, Eni has made new oil discoveries in Block OML125, that will feed the ABO field; it has made further discoveries in the Norwegian Barents Sea, which will consolidate the reserve base for the development of Johan Castberg. The rediscovery of Oglan in Ecuador will rapidly be brought into production and, finally, the new gas discovery in Indonesia through the Merakes well, in the East Seppingan block, which, given its proximity to the Jangkrik development field and the Bontang liquefaction facilities will be able to transport additional volumes of gas to the plant. In 2013 Eni adopted an organic approach to the exploration of non-conventional shale oil resources, by entering the relatively unexplored area of the Delaware basin in West Texas, where a first well, the Stalling 1H, has been drilled and put into production, with an initial daily oil output of around 750 barrels.

Latest developments

Last month Eni, together with Statoil, Sasol and ENH, was awarded, following the 5th Competitive Mozambique Bid Round, the exploration and development rights of the offshore block A5-A, in the area of Mozambique named Angoche, about 1,500 kilometres northeast of the capital city Maputo. The block, which covers a total area of 5,145 square kilometres in a water depth between 200 and 1800 meters, is situated within an unexplored area of the Northern Zambezi Basin, which the consortium estimates to contain significant hydrocarbon resources. Eni, through its subsidiary Eni Mozambico, is the operator of the joint venture, with a 34% stake. Eni has been present in Mozambique since 2006 and is the operator of Area 4, owned through its subsidiary Eni East Africa. In Area 4, following an intensive exploration campaign and appraisal, from 2011 to 2014, Eni also discovered •

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supergiant natural gas resources, estimated in 2.4 billion of cubic meters of gas in place. Also last month, Eni announced the success of the Nidoco North West 3 well drilling in the Nooros exploration prospect, located in the Abu Madi West licence in the Nile Delta, which is estimated to contain about 15 billion standard cubic metres of gas. The field was discovered in July this year and put into production after only two months; it currently produces more than 15,000 barrels of oil equivalent per day (boepd). Production from the new well will start by the end of November this year. By the end of 2015, Nooros field will produce 30,000 boepd and is expected to reach a plateau of 70,000 boepd in the first half of 2016. The gas and condensates are sent to the Abu Madi’s treatment plant, about 25 kilometres from the discovery, and then routed in the Egyptian network. Similarly to the discovery well, Nidoco NW3 was drilled from onshore to reach the Noroos reservoir located in the offshore shallow waters. The well encountered a 65 metre thick gas bearing sandstone layer of Messianian age with excellent petrophysical properties. In parallel with the field development, Eni will continue its exploration activities in the licence area, where it has identified a significant additional potential which will be tested through the drilling of other three new exploration wells. Eni, through its subsidiary IEOC, holds a 75% stake in the Abu Madi West licence, while BP holds a 25% stake. The operator is Petrobel, held equally by IEOC and by the state company Egyptian General Petroleum Corporation (EGPC). Eni reported in October that it reached a new production of 73,000 barrels of oil per day in the Western Desert of Egypt, doubling in just three years the level of production in the area. The production increase is attributed to production growth in the Melehia West Deep field, located 290 kilometres west of Alexandria. The new field, which contains oil and gas in the Lower Cretaceous and Jurassic’s deep geological layers, was discovered on January 2015 and, following an appraisal campaign, it has already 56

•

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achieved a production level of 12,000 barrels of oil per day. Eni expects to bring production in the Melehia West Deep Field to over 15,000 bopd also thanks to the start-up of the first treatment plant and the gas export of Melehia’s license by end of November. These new finds with immediate return of production capacity are the result of Eni’s new strategy in the country, where the rapid development of the discoveries has been possible through existing infrastructures and synergies. Eni has been present in Egypt since 1954 where it operates through IEOC. The company is the leading producer in the country with an equity production of around 190,000 barrels of oil equivalent per day.

The future

Claudio Descalzi, Eni’s chief executive officer, outlines the company’s growth strategy: “Since last summer Eni’s transformation into a more closely integrated oil and gas business has made significant progress. While maintaining our focus on our exploration success we have achieved the turnaround of Gas & Power one year earlier than expected and the restructuring of our Refining & Marketing activities will lead us to break even in 2015. Despite this success, the oil price fall means our 2015-2018 plan is predicated on much lower oil prices. We have taken a series of additional measures, including capex optimizations and opex and G&A reductions, all of which will strengthen the business. The decision to re-base the dividend in 2015 is appropriate and in line with our strategic objectives considering the new oil price scenario. It sets a level from which sustainable returns can be delivered while maintaining a progressive dividend policy with underlying earnings growth.” Given the current oil price, Eni is putting in place plans to ensure continued improvement and growth in the upstream area, made possible by its ability to discover large new hydrocarbon reserves and rapidly complete 70 major development projects in geographically diversified areas, most of which have already started. It also plans to complete the

• Eni

“We have achieved the turnaround of Gas & Power one year earlier than expected and the restructuring of our Refining & Marketing activities will lead us to break even in 2015”

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restructuring process in the mid-downstream, severely affected by the recent crisis in the European gas and refining market, bringing the businesses back to breakeven and later to profit. Exploration remains an important growth driver for the company. In the first two years of the 2015- 2018 plan, activity will be focused on proven plays and near-field exploration in order to quickly complete the full appraisal of resource potential, while benefiting from all the logistical advantages in development and production start-up activities. The hydrocarbon production growth target will be achieved mainly through the start-up of 16 major projects and the ramp-up of those already started in 2014, with a total contribution in excess of 650kboed in 2018. Gas & Power’s restructuring plan, which accelerated remarkably in 2014, will be completed in the four-year plan. The plan will see full alignment of gas supply costs to market prices and substantial recovery of pre-paid take or pay volumes by 2016; simplification of the operational structure and optimization of logistical costs with savings of 300 million euros by 2018; development and growth in high value segments, in particular in retail, trading, and LNG. In order to address the structural weaknesses expected in Refining over the next four years, Eni will complete the transformation process of the R&M segment through completing the rationalization and reconversion process of facilities in Italy and overseas, make continuous efficiency improvements, and develop marketing activities worldwide. In conclusion, the strategic transformation outlined in the plan will lead to a much more robust Eni, which will be able to face a period of lower oil prices while continuing to create value in a sustainable way.

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