Oil, Gas and Shipping Magazine

ISSUE 87 www.ogsmag.com

On the cover

Statoil:

Embracing challenges Statoil, the state oil company of Norway and the leading operator on the Norwegian continental shelf, is in a phase of international expansion, especially in subsea development, where the future is longer, deeper and colder. Page 6

In this issue Shale gas to fill the energy gap: The UK Government must prepare for shale gas production. Page 32

Trusting in trade: Dr David Blond reflects on a lifetime in economics and observes how the same issues keep coming back to haunt us – like free trade and tariffs.

Page 48

News & Features Page 21

HARD WORKING ENGINEERS We have turned things around before.

No matter what the oil price is: The world needs energy.

It is at times like these new technology and new processes see the light of day. Together we have turned things around before – by innovating, reducing costs, and working in a smarter way. We are all adjusting once again, to make sure we can succeed in the new market reality.

And we know we can do what it takes.

Now is the time to get together and prepare for the future. ONS 2016 provides you with the latest insights, the new technology – and future business opportunities.

This is the place to be. Welcome to the leading energy meeting place.

www.ons.no New conference feature: Build your competence at our new Technical Sessions!

• The Editor

Taking the slow road

Editor

The

T

he Scottish traditional song Loch Lomond lays down a challenge. “You take the high road and I’ll take the low road and I’ll be in Scotland afore ye.” No one is sure who wrote it or what it means. We don’t know the starting point, the specific destination, the relevant merits of the roads, nor the capabilities of the rivals—it’s an intriguing enigma.

When we embark on a journey, we generally have a choice of routes, too, depending on whether we are travelling for business or pleasure. Do we want to get there quickly or take the scenic route? The latest SatNav systems offer routes avoiding motorways and roadworks.

In international trade, however, journey time and cost are important factors in the choice of route, so I was intrigued once more to find another enigma in an unlikely place. A recent report from the US Energy Information Administration reveals that a growing number of oil shipments from the Middle East

Martin Ashcroft

to the ports of Amsterdam, Rotterdam and Antwerp in Europe are being routed around the southern tip of Africa on a journey taking a month or more, rather than through the Suez Canal, which would have cut the journey in half.

If shorter is cheaper, why would you choose to go the long way round? It’s not for the scenery. It’s all about price. ‘You take the fast route and I’ll take the slow route and I’ll get a better price than you do’, is how a Scottish poet might have put it.

It’s a quirk of the futures market (known in the trade as contango) when prices for delivery dates much further in the future are higher than those for earlier delivery. When contango in futures contracts is large enough, it’s possible to lock in a profit by purchasing distillate supplies on the spot market, chartering a vessel, and selling a longer-dated futures contract. Floating storage ‘on the move’, you might say, heading for the bonnie, bonnie banks of the North Sea. •

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Contents Page 6

Statoil: Embracing challenges

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The Editor: Taking the slow road

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Total starts gas production from Laggan-Tormore

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Statoil: Embracing challenges

31

Energy leaders’ concerns: New test for contamination

21

News in brief

32

Shale gas to fill UK energy gap

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Harding lands Culzean lifeboat contract

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Kosmos gas discovery offshore West Africa

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Damen delivers to Maersk: ABB wins UAE contract

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US builds terminals for export of LNG

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Oil supply growth in Iraq: Canadian oil production

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Interview: Andrew Clifton, general manager, SIGTTO

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Diminishing economies of scale from megaships

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David Blond’s economics: Trusting in trade

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First US shale gas to Europe: Edinburgh Business School

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Comment: North Sea oil companies must innovate

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Comment: Unconventional gas is changing markets

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Saudi Aramco: Where energy is opportunity

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Shale gas to fill UK energy gap

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Page 44

Interview: Andrew Clifton of SIGTTO

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Page 42

US builds terminals to export LNG

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statoil Embracing challenges Statoil, the state oil company of Norway and the leading operator on the Norwegian continental shelf, is in a phase of international expansion, especially in subsea development, where the future is longer, deeper and colder •

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As a leading international energy company with operations in 33 countries, Statoil is well used to identifying and meeting the many challenges the oil and gas business presents. Building on more than 40 years of experience from oil and gas production on the Norwegian continental shelf, Statoil is committed to applying technology to create innovative business solutions.

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The company, headquartered in Stavanger, Norway and with approximately 23,000 employees worldwide, believes that competitive returns for its shareholders are best achieved through a values-based performance culture, stringent ethics and a code of conduct which promotes personal integrity.

Safe and efficient operations are Statoil’s first priority, and the company is renowned for its technical safety monitoring system and safe behaviour programme. Statoil also aims to meet the demand for energy, necessary for further economic and social development, while showing consideration for the environment and making an active effort to fight global climate change. It focuses on contributing to sustainable development via its core activities in each country in which it operates.

Statoil has grown alongside the emergence of the Norwegian oil and gas industry, dating back to the late 1960s. Today, the company is one of the world’s largest suppliers of oil and gas. In 1972, the Norwegian State Oil Company, Statoil, was formed, and two years later the Statfjord field was discovered in the North Sea. In 1979, the Statfjord field commenced production,

• Statoil development projects. Partner-operated fields represent a significant proportion of Statoil’s oil and gas portfolio. The portfolio ranges from development projects to mature fields.

The complexity of these requires detailed knowledge of the areas involved.

Johan Sverdrup

One of Statoil’s most ambitious and challenging projects is Johan Sverdrup, a gigantic field currently under long term development and with massive potential for both Statoil and for Norway. Johan Sverdrup is situated in mature acreage that has been thoroughly studied, and where the most central environmental aspects are that the development receives its power from land; that produced water will be purified and re-injected into the reservoir; and that cuttings drilled with oil-based liquid will either be brought ashore, or purified and discharged offshore.

“Statoil believes in a values-based performance culture, stringent ethics and a code of conduct which promotes personal integrity”

Start of the drilling operation of Johan Sverdrup field

and in 1981 Statoil was the first Norwegian company to be given operator responsibility for a field, at Gullfaks in the North Sea. Statoil merged with Norsk Hydro’s oil and gas division on 1 October 2007. The new company was given the temporary name of StatoilHydro, but changed its name back to Statoil on 1 November 2009. Norsk Hydro’s oil history stretches back to the late 1960s, when the company was a license holder in the giant Ekofisk discovery in the North Sea in 1969. Statoil has been one of the most important players in the Norwegian oil industry, and has contributed strongly to Norway’s development as a modern industrial nation. Today, Norway is one of the world’s most productive petroleum provinces and a test lab for technology development.

Statoil is the leading operator on the Norwegian continental shelf, and a company in an expansive phase internationally.

As the fields on the Norwegian continental shelf become increasingly mature, Statoil is actively seeking international opportunities to apply its expertise in offshore and deep water

Planning of Johan Sverdrup commenced in March 2012 and building and installation is due for completion in 2019.

Work in phase 1 is based on standard technology, though development will be demanding due to the size of the project. Even though the project is immense and somewhat daunting in terms of size at 200 square kilometres, Statoil’s previous experience of complex, major projects, as well as the company’s experience of smaller field developments with tough standardisation and industrialisation requirements, will prove to be most valuable here.

Statoil also has the support of its partners’ experience; and the goals set by the authorities for the NCS. Statoil and the industry possess extensive experience of seabed development solutions in this area. With ocean depths of 110 - 120 metres and good reservoir characteristics, development is therefore possible without having to resort to new, customised solutions – at least, not yet.

The first phase of the field centre includes a process platform, drilling platform, riser platform and accommodation platform.

The installations, which have steel jackets, are linked by bridges and stand in ocean depths of between 110 and 120 metres. The field centre will extend over approximately 700 metres. The accommodation quarters will contain 450 cabins.

At production start-up in the first phase of the development, planned for late 2019, total capacity will be between 315,000 and 380,000 barrels per day. Statoil expects to drill a total of 35 production and injection wells in connection with phase one.

A number of wells will be pre-drilled from 2016 to speed up production at start-up, which is planned for 2019.

Total first-phase investments will amount to NOK 117 billion (2015 value). These include a field centre and four platforms, wells, export solutions for oil and gas, plus power supply. The estimate also includes unforeseen costs and provisions for market adjustments. In addition, preparations will be made for increased oil recovery during the first phase.

The partners have chosen land-based power supply for the •

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Independent global consultants supporting our clients to improve their commercial performance and achieve better cost, quantity measurement and schedule predictability throughout the project lifecycle

“It’s all about adding value for our clients by reducing costs, regardless of whether it is through a small bespoke intervention or delivery of a major programme.” Chris Stops, Director, Turner & Townsend Energy

Depth of experience From Statoil’s first field, to the Sleipner platform, to projects today, we have been involved in more than 15 of Statoil’s major developments on the Norwegian continental shelf since 1980.

Our latest role is in support of the Johan Sverdrup field development, preparing major construction contracts packages.

For further details, a presentation or demonstration of how we can help your project achieve a more competitive and predictable outcome please contact Chris Stops. t: +44 (0) 7958 830308 e: chris.stops@turntown.co.uk www.turnerandtownsend.com

Driller at Johan Sverdrup field

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• Statoil

“Statoil is renowned for its technical safety monitoring system and safe behaviour programme”

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• Statoil Johan Sverdrup field in the first phase, which will reduce total climate gas emissions by 80% to 90%, when compared with a standard development procedure involving gas turbines on the NCS. In addition, energy efficient solutions are being given priority in order to reduce total energy consumption.

“Planning of Johan Sverdrup commenced in March 2012 and building and installation is due for completion in 2019” The oil and gas for export from Johan Sverdrup will be piped ashore. The oil will then be transported to the Mongstad terminal in Hordaland, while the gas will be transported via Statpipe to Kårstø in Rogaland – in a new 165-kilometre-long gas pipe – for processing and onward transport.

Once it becomes fully operational the Johan Sverdrup field may well turn out to be the most significant on the Norwegian continental shelf since the 1980s.

Subsea

Besides being a leading operator of innovative floating production platforms and production ships, Statoil has an enviable record in producing hydrocarbons via subsea (seabed) installations. Its goal is to maximize the production on the Norwegian continental shelf and lay the ground for further growth.

To achieve this, further technology development is being pursued along the lines of compact and environment-friendly solutions to improve recovery from the reservoirs, and allow long tie-backs to land and equipment for ultradeep water.

“Statoil aims to develop the elements required for a subsea factory by 2020” Once the equipment has been developed and installed, efficient intervention systems are essential for carrying out modifications and repairs – both in the well and on the seabed.

Dedicated high-capacity vessels for seabed intervention, modification and repair (IMR), light well intervention (LWI), and through-tubing rotary drilling (TTRD) have been developed to achieve fast response times. These in turn enable high levels of productivity and reservoir recovery.

Statoil is taking subsea longer, deeper and colder. Through innovative thinking and collaboration with partners and suppliers, Statoil aims to develop the elements required for a subsea factory by 2020—a process plant on the seabed making it possible to utilize remote-controlled transport of hydrocarbons at any offshore facility.

Future resources are further from land, at greater depths and in colder and harsher environments. The subsea factory will be vital to realise business opportunities for Statoil in these areas and help to realise its production goal of 2.5 million barrels of oil equivalent (boe) per day by 2020. Statoil believes that compact separation facilities on the seabed will be a key

to success in the Arctic or in deepwater areas like the Gulf of Mexico and Brazil.

Statoil’s offshore portfolio is well suited to the application of subsea production and processing. It operates 500 subsea wells and has a 25-year track record of subsea technology development, implementation and operation. It has already taken the first technological steps, making the world’s first complete subsea solution for separation and injection of water and sand from the Tordis wellstream, and has developed the first subsea facility for injection of raw seawater on Tyrihans.

Projects such as the oil-dominated multi-phase transport on Tyrihans and Snøhvit’s gas condensate transport are at the forefront in the development of multi-phase transport over long distances.

Shale

Shale resources have begun to transform the global energy outlook. Due to reserve additions from shales, global natural gas reserves are estimated by the International Energy Agency (IEA) to last around 250 years at present consumption levels.

According to the IEA, unconventional gas (shale gas, tight gas and coal bed methane) now makes up 60% of marketed production in the US and production estimates of tight oil in the US alone could exceed 1.4 million barrels per day by 2020.

For Statoil, shale and tight rock reservoirs are a key growth area that increases its long term reserve base. Statoil’s heritage as a pioneering company and its technological competence give it a strong foundation for its strategic ambitions in shale.

The development of shale and tight rock resources enables both local and global economic development, creating jobs and wealth at the local and national level, while also meeting growing world energy needs.

Statoil’s shale and tight gas and oil business began in the US through active partnerships in the Marcellus play along the eastern seaboard, the Eagle Ford play in south Texas, and its own operation of tight oil activities in North Dakota and Montana in the Bakken play. Shale and tight rock opportunities are in the early stages of development in many other parts of the world.

What about the alternatives? Statoil is leading the way in harnessing new energy sources, including carbon capture and storage, as well as wind energy. Carbon capture and storage (CCS) makes an important contribution toward reducing CO2 emissions, and Statoil is actively pursuing CCS in many areas.

It has stored CO2 on Sleipner Vest since 1996, and continues to be a champion for the development of CCS. New renewable energy is one of the most exciting growth areas in the energy market. Statoil is focusing on establishing a position in markets where the company has natural advantages, particularly within offshore renewable energy.

The world’s energy demands are such that oil and gas will be key energy sources for decades to come. At the same time, sustainability is becoming increasingly important. Statoil built its knowledge base on the development and production of oil and gas, and currently leads the world in energy efficiency and low CO2 emissions. The current focus is on continuing this position, combined with a gradual build-up in the field of renewable energy. But exactly how these competences should be used to serve the company best raises questions for the company to answer over the next few years.

Since Statoil was founded in 1972, the State has developed this premium asset. The stock exchange listing in 2001 and •

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• Statoil

“Shale and tight rock reservoirs are a key growth area that increases Statoil’s long term reserve base”

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• Statoil

the merger between Statoil and Hydro oil and gas in 2007 were important to create an international energy company.

The ability to handle risk, seize opportunities for growth and ensure future value creation are also linked to the company’s size. Safe and efficient operations, technology development, innovation and active exploration activity will remain the engines in Statoil’s development. But also in the future, structural adaptations may be instruments to develop global competitiveness.

In the next 40 years, Statoil will be moving into new and demanding territory. The answers to tomorrow’s challenges are not going to be easy, and will be shaped by the company’s capacity for adaptation, reflection and a continued willingness to discuss the alternatives and dilemmas it faces.

Strict requirements and high expectations for health, safety and the environment from the authorities and its stakeholders have given Statoil and the Norwegian oil industry a competitive advantage. The company sees no long-term conflict between the interests of its owners and society’s expectations. Statoil’s aim is to continue to deliver solid returns to its shareholders, while operating in a way that builds trust and understanding for what it does.

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News in Brief

news & features

Iran’s crude oil production has been relatively flat over the past three years while sanctions were in place, averaging 2.8 million barrels per day (b/d) in 2015, representing 9% of OPEC’s total crude oil production. In EIA’s January Short-Term Energy Outlook, which assumed implementation day to occur this quarter, Iran’s annual average crude oil production is forecast at 3.1 million b/d in 2016 and almost 3.6 million b/d in 2017. * * *

SAL Heavy Lift has been engaged

by Dutch Offshore WindForce, a JV between Boskalis and Volker Stevin International, to transport 67 transition pieces destined for the Veja Mate Offshore Windfarm in the German North Sea. SAL will make 12 voyages from Aalborg, Denmark to Eemshaven, Netherlands where the transition pieces will be handed over to a specialized installation vessel. Each of the 67 transition pieces is over 25 meters long and weighs approximately 360 tons. * * *

Container service reliability had a poor start to 2016 with the average ontime performance slipping by 5.7% in January to 69.6%, according to Carrier Performance Insight, the online schedule reliability tool from Drewry Supply Chain Advisors. The three most reliable carriers in January were the same as for December 2015, with Japanese carrier MOL ahead with an average on-time performance of 82.7%, Wan Hai in second place with 79.5% and Maersk Line in third spot with 77.0%. * * *

Datum360, a UK engineering information management provider, has partnered with Kuwait based Enterprise Business Solutions, who will provide Datum360’s Software as a Service (SaaS) offering across the Middle East from its locations in Saudi Arabia, UAE, Bahrain and Qatar. EBS provides refineries and factories in the Middle East with solutions for streamlining and running plants and Datum360’s expertise in engineering information management makes this signing an ideal business alignment.

Harding lands Culzean lifeboat contract H arding extended its string of offshore successes with contracts for lifeboats and davits to the Culzean offshore gas complex, to be constructed for owner Maersk Oil UK

by Sembcorp Marine subsidiary SMOE PteLtd of Singapore.

The Culzean win gives Harding a sweep of the latest big offshore contracts, including deliveries of lifeboats and davits to the Heerema heavy lift semisubmersible crane Sleipnir and to the giant Johan Sverdrup field centre.

“We have worked hard to strengthen our position in today’s difficult offshore market,” says Harding’s global director of sales Bjørn Sturle Hillestad. “Winning the Culzean project was a key strategic goal in this process.”

Culzean is one of the largest gas discoveries of recent years in the UK North Sea, and the field centre will comprise a 12-slot wellhead platform (WHP) linked by bridges to a central processing facility (CPF), supported by a floating storage and offloading vessel (FSO) and an installation for utilities and living quarters (ULQ).

Harding will deliver three FF1200 lifeboats to the ULQ and one FF1200 to

the WHP, both with LA1200SU davits.

The davits are scheduled for delivery by March 2017, with the lifeboats to follow in December of the same year. The WHP/FSO contract is still in bid phase.

The FF1200 is a 70-person free fall lifeboat designed to meet the most stringent standards in the industry, and with just more than 100 delivered, it is among the most popular in the industry.

The LA1200SU is a skid-launch davit specially designed for the FF1200.

“Competition isn’t getting any easier, so we are very happy and proud to have won these latest contracts,” reports Harding regional sales director Odd Åge Helvik.

Bjørn Sturle Hillestad, Harding’s global sales and marketing director, emphasises that good communications are key in winning good contracts. “Our first job is to earn customer confidence, to build their trust in Harding quality, and we have plenty of good references to help us there,” he relates. “Then we listen. We learn about their concerns and preferences, and help them to understand that we are committed to delivering exactly what they need, not just a standard product line.”

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Damen delivers cable installer to Maersk Supply Service

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n February the DP2 cable installation vessel Maersk Connector was handed over from Damen Shipyards Group to Maersk Supply Service. The vessel is going directly on a long-term charter for subsea services provider DeepOcean. Based on Damen’s DOC 8500 platform, the vessel has been customised to meet the challenges of reducing offshore renewables costs.

“We’ve already been awarded three UK and North Sea contracts for Maersk Connector, so we’re very satisfied,” reports DeepOcean Commercial Director Pierre Boyde. “The working relationship has been productive and Damen has delivered a state-of-theart cable installation vessel. Maersk Connector is fine-tuned around DeepOcean’s 20 years’ experience of installing and trenching more than 1,000 kilometres of power cable and backed up with Maersk Supply Service’s long pedigree of superior marine operations.”

Owned and operated by Maersk Supply Service, the vessel is the latest addition

to the 50-plus strong Maersk offshore support vessel fleet. Søren Karas, chief commercial officer of Maersk Supply Service, praises the constructive cooperation between the three parties.

“Maersk Connector is the result of a successful tri-party cooperation between a quality yard, an experienced subsea service provider and a leading vessel owner and marine operator.

Throughout the process there was

“Maersk Connector is the second of a new generation of cable-laying vessels” close communication between all parties, focused on finding solutions.

Maersk Supply Service is very happy with the outcome resulting from this cooperation; the vessel has been delivered on time, on budget and

the quality is good. We are excited to embark on the long term cooperation with DeepOcean supporting their subsea operations.”

So far the vessel has been contracted to undertake marine works for three DeepOcean contracts: the Walney Extension Project, the Nemo Link® interconnector and the Bligh Bank Phase II Offshore Wind Farm. In combination with new survey, trenching and installation equipment, much of which has been awarded to UK manufacturers, Maersk Connector enables DeepOcean to deliver more efficient, cost-effective and safer cable installation.

Built at Damen Shipyards Galati in Romania, Maersk Connector is the second of a new generation of cablelaying vessels based on the proven Damen Offshore Carrier (DOC) platform. Developed as a flexible platform for both transport and installation work offshore, the DOC 8500 is 138 metres in length and has a beam of 27.5 metres.

ABB awarded $18 million contracts on unmanned UAE oil platforms

A

BB has won orders worth around $18 million from National Petroleum Construction Company (NPCC) for the delivery of electrical and telecommunication systems to the Al Nasr Full Field Development Project in Abu Dhabi.

This will enable NPCC to fulfil its obligations to Abu Dhabi Marine Operating Co, which include safe operation of seven wellhead towers approximately 130km northwest of Abu Dhabi City. Coupled with last year’s orders for the project, ABB will deliver a seamless electrical distribution system, including powerfrom-shore, covering the complete Al

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Nasr oil field.

“Tight power and automation integration is a key element of ABB’s Next Level strategy to ensure safe, reliable and efficient operations for our customers,” said Peter Terwiesch, President of ABB’s Process Automation Division. “These continuing orders affirm the strength of our long-standing relationship with Hyundai Heavy

Industries and NPCC for this project.”

ABB will supply 11kV and 6.6kV airinsulated and low voltage switchgear that continually provide data to verify and ensure a high level of safety, availability and reliability. ABB is also providing a fully integrated telecommunication system to the super complex for internal and external communication and field security.

Key products are computer networks, electronic personnel tracking, camera system, radar, public address and general alarm systems, access control, telephone system, radios and a transmission system between platforms. Delivery is scheduled for the second half of 2016.

news & features

Oil supply growth in Iraq second only to United States Iraq was the second-leading contributor to the growth in global oil supply in 2015, behind only the United States, according to analysis by the US Energy Information Administration.

Crude oil production in Iraq, including fields in the Kurdistan Region of northern Iraq, averaged 4.0 million barrels per day in 2015, almost 700,000 b/d above the 2014 level.

Iraq is the second-largest oil producer in the Organization of the Petroleum Exporting Countries (OPEC) and accounted for about 75% of total OPEC production growth in 2015. Iraq’s oil consumption decreased slightly in 2015, and as a result, all of the crude oil production increase was exported to international markets.

In southern Iraq, where almost 90% of the country’s oil was produced in 2015, the upgrade of midstream infrastructure

(pipeline pumping stations and storage facilities) and improvements to crude oil quality contributed to increased production.

In June 2015, Iraq started marketing Basra heavy grade crude oil, distinguishing it from the Basra crude

it had traditionally marketed as a light crude oil. Before this distinction, Iraq limited its production at oil fields producing heavy oils to maintain the minimum standard for the light grade Basra crude oil.

Once Iraq began marketing Basra

heavy separately from Basra light, it was able to increase production at fields producing the heavier oil and improve the quality of Basra light. In northern Iraq, where the remaining 10% of Iraq’s oil was produced in 2015, the Kurdistan Regional Government (KRG) increased the capacity of its independent pipeline, allowing output increases.

The Iraqi Oil Ministry publishes monthly data on exports and revenues.

On average, Iraqi crude typically sells $5/b to $10/b less than Brent, a global crude oil price benchmark. The KRG does not publish its official selling price, though crude marketed by the KRG is typically sold at a lower price than the rest of Iraq. The KRG is also experiencing budgetary constraints that are causing payment delays to IOCs, which will likely contribute to slowing production growth this year.

Canadian oil production is likely

which totaled 4.5 million barrels per day in 2015, is expected to average 4.6 mb/d in 2016 and 4.8 mb/d in 2017.

The increase is accounted for by growth in oil sands production of about 300,000 b/d by the end of 2017, which is partially offset by a decline in conventional oil production.

Extremely low prices suggest that many oil sands projects may be

operating at a loss, but these projects are designed to operate over a period of 30 to 40 years and can withstand volatility in crude oil prices.

Additionally, the cost to shut down an existing oil sands project is estimated to be in the range of $500 million to $1 billion, which may exceed the operating losses a producer might experience in the short term.

to continue increasing through 2017, according to the US EIA, as oil sands projects already under construction when prices began to fall in 2014 are expected to begin production in the next two years.

According to EIA’s February ShortTerm Energy Outlook, production of petroleum and other liquids in Canada,

Iraq is the secondlargest oil producer in OPEC

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news & features

Diminishing economies of scale from new generation of megaships

T

he economies of scale associated with the increasing size of container ships may be running out, according to a study by global shipping consultancy Drewry, into the operational and financial impacts on lines, terminal operators, ports and other supply chain stakeholders as vessel sizes increase up to and beyond 18,000 teu (twenty-foot equivalent units, the standard metric used to measure a ship’s cargo carrying capacity).

Since 2009, leading container shipping lines have engaged in a new-build ‘arms race’ with vessel sizes increasing at breakneck pace to drive down unit costs and improve profitability. This race-to-scale is set to continue with a further 53 megaships expected to enter service in 2016.

While bigger ships help carriers reduce voyage costs, these savings are increasingly offset by higher port and landside costs, meaning that total system cost savings are small and declining.

Larger vessels place greater demands on ports, where channels have to cater for deeper draughts, and on terminals

which need to upgrade equipment, yard facilities and manning levels to handle increased peak cargo volumes. On a total ‘system cost’ basis the study found that the upsizing of vessels provides only modest savings for the overall supply chain with efficiency gains being further eroded as vessel size increases beyond 18,000 teu.

productivity improvements from the transport system are to be realised.

“Addressing the operational and cost effects at port facilities caused by the challenging load and discharge patterns of these larger ships requires a crossindustry effort. All stakeholders in the supply chain must recognise the need for dialogue and collaboration if the maritime transport system as a whole is to benefit. If these benefits cannot be delivered and economies of scale in this industry really are running out, the implications are profound.”

There is a wider possible implication of these findings for the industry: if economies of scale in liner shipping have finally run their course, future vessel ordering will no longer be driven by the need to secure economies of scale but will instead be based on lines’ assessment of future demand growth.

“When this happens, the tendency to structural overcapacity that has plagued the industry will be much reduced,” added Power. “If this were combined with a process of continuing industry consolidation, liner shipping might at last be in a position to generate sustainable profitability.”

“While bigger ships reduce voyage costs, these savings are increasingly offset by higher port and landside costs” “As more megaships enter service the industry is rapidly approaching a critical stage,” said Tim Power, managing director of Drewry. “To ensure the economics of vessel upsizing continue to benefit the entire supply chain, lines and ports need to work in a more coordinated manner if further •

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First US shale gas imported into Europe

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he INEOS Intrepid, the world’s largest LNG multi gas carrier, is bringing 27,500m3 of US shale gas ethane from the Markus Hook terminal near Philadelphia to Rafnes in Norway.

This is the first time that US shale gas has ever been imported into Europe and represents the culmination of a longterm investment by INEOS. The shale gas is cooled to -90ºC (-130ºF) for the journey of 3,800 miles, which is expected to take nine to ten days. US shale gas will complement the reducing gas feed from the North Sea. The INEOS Intrepid is one of four specially designed Dragon class ships that will form part of a fleet of eight of the world’s largest ethane capable carriers.

“Shale gas economics has revitalised US manufacturing,” says Jim Ratcliffe, the chairman and founder of INEOS. “When US shale gas arrives in Europe, it has the

E

potential to do the same for European manufacturing.”

The ethane gas being shipped to Europe originates from the Marcellus Shale in Western Pennsylvania, 300 miles from the nearest port. The Mariner East Pipeline has been constructed by Sunoco

site since 1902. Due to changing market conditions, the refinery closed in 2012 but the INEOS project meant that the site could be reopened.

To receive the gas, INEOS has built the two largest ethane gas storage tanks in Europe at Rafnes in Norway and Grangemouth in Scotland.

INEOS will use the ethane from US shale gas in its two gas crackers at Rafnes and Grangemouth, both as a fuel and as a feedstock. It is expected that shipments to Grangemouth will start later this year.

“We are nearing the end of a hugely ambitious project that has taken us five years,” adds Ratcliffe. “I am proud of everyone involved in it and I believe that INEOS is one of very few companies in the world who could have successfully pulled this off. I can’t wait for the INEOS Intrepid to get to Norway and complete the job.”

“Shale gas has the potential to revitalise European manufacturing” to deliver ethane to the Marcus Hook facility near Philadelphia, an 800 acre site on the banks of the Delaware River that has been an oil and gas processing

dinburgh Business School, the Graduate

School of Business of Heriot-Watt University, has launched a specialist MBA in Oil and Gas Management. To attain the new qualification students will undertake the seven core courses of the Edinburgh Business School MBA, followed by specialist courses in finance, project management, strategic planning and strategic negotiation for the oil and gas industry.

For the 2015/16 academic year the four specialist oil and gas courses will be available through a combination of self-study and five day intensive seminars at the school’s campuses in Edinburgh or Dubai, or with its learning partners in Nigeria and Trinidad. From late 2016 the courses will be available in all study modes including self-study online.

“The specialist courses have been developed in conjunction

with real world oil and gas industry experts, as well as our global teaching partners, to ensure we are providing the most relevant programme to help professionals manage the sector’s future,” said Craig Robinson, who has led the academic development at the Business School.

The Edinburgh Business School MBA with Specialism in Oil and Gas Management extends the school’s expertise and experience in the oil and gas arena. The school developed an MSc in Management for the Oil and Gas Industry exclusively for Schlumberger, the world’s largest oilfield services company, and this programme has been successfully running for nine years. In total more than 120 Schlumberger employees have graduated from the MSc programme and there are 130 active students.

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Total starts gas production from Laggan-Tormore, West of Shetland

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otal has started production from the Laggan and Tormore gas and condensate fields, which are expected to produce 90,000 barrels of oil equivalent per day (boe/d).

Approximately 125km north-west of the Shetland Islands, the Laggan and Tormore fields lie in an area known generically as West of Shetland – a region geographically closer to the North Atlantic than the North Sea – on the edge of the UK continental shelf, where water depths descend rapidly from an average of 120 metres (393ft) to more than 600 metres (1,968ft).

The Laggan-Tormore development consists of a 140 kilometre tie-back of four subsea wells to the new onshore Shetland Gas Plant, which has a capacity of 500 million standard cubic feet per day. Following treatment at the gas plant, the gas is exported to the mainland via the Shetland Island Regional Gas Export System (SIRGE) and the condensates are exported via the Sullom Voe Terminal.

Laggan was discovered in 1986 and

“Laggan-Tormore is a key component of our production growth in 2016 and beyond,” said Total’s president of exploration & production, Arnaud Breuillac. “The innovative subsea-toshore development concept, the first of its kind in the United Kingdom, has no offshore surface infrastructure and benefits from both improved safety performance and lower costs.

“By opening up this new production hub in the deep offshore waters of the West of Shetland, Total is also boosting the United Kingdom’s production capacity and Europe’s energy security.”

Until today, only oil was recoverable from this area, but with the new pipelines and infrastructure in place, previously inaccessible gas resources can be developed.

Laggan-Tormore is the first completely sub-sea development in UK waters with the longest tie back to an onshore terminal instead of a platform. Total decided against surface platforms because of the deep water and harsh weather conditions.

Tormore was discovered in 2007.

Total was given approval by the UK Government in 2010 to develop both fields together. With an estimated lifespan of 20 years, the fields are expected to provide about 8% of the UK’s gas needs - the equivalent of about two million homes.

Almost a fifth of the UK’s oil and gas reserves are thought to lie in the area to

“Laggan-Tormore is a key component of our production growth in 2016 and beyond” the west of Shetland, and the Shetland Gas Plant is said to be the biggest construction project in the UK since the London Olympics. The project is part of a massive £3.5bn investment by French company Total.

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What keeps energy leaders awake at night?

ow in its seventh year, the World Energy Council’s annual survey of global industry leaders, the 2016 World Energy Issues Monitor, tracks the concerns of over 1000 global energy leaders. This year’s report A climate of innovation – Responding to the commodity price storm highlights for the first time the views of China’s energy leaders among the over 30 nations represented in the study.

“This year we see that industry leaders remain most concerned about commodity price volatility, global recession and climate framework uncertainty with new market design and electric storage featuring as new items of innovation focus;” said Christoph Frei, Secretary General of the World Energy Council, “The quest to finance the transition to a more sustainable energy system remains an issue that keeps leaders busy at work, whilst there is a growing acknowledgement that adaptation to new resilience challenges, smart innovation and regional interconnection will be key parts of the

be very clear what their strengths and priorities are. The report says that the three key drivers of change will be: • Decarbonisation transition – a wide range of different new technologies are becoming a reality • Market design transition - increasing shares of zero-marginal-cost energy from intermittent renewables in combination with the decentralisation of systems; increasing use of smart data, and decreasing entry barriers for new suppliers.

• Resilience transition - the impact of extreme weather events, cyber security threats and the energy-water-food nexus.

How companies and industry can work together to facilitate a move to a low carbon economy will be a key theme at the 23rd World Energy Congress which takes place in Istanbul in October 2016. The report’s findings provide information to leaders and policymakers in nearly 100 countries and guide the structure for the discussions at the Congress.

solution.”

After the Paris COP21 talks, the World Energy Issues Monitor shows that the energy sector is entering a period of transition where three powerful

“Industry leaders remain most concerned about commodity price volatility, global recession and climate framework uncertainty” drivers will influence change and result in different ways of thinking about infrastructure and critical system components. To navigate these transitions with limited resources defined by a sluggish growth context, investors and governments have to

Conidia launches new test for fuel contamination

Microbial contamination of fuel storage tanks has become a serious problem, particularly with the introduction of biodiesels. If the issue is not addressed the resulting growth can form a “sludge” which blocks filters, fuel lines and in worst case scenarios, causes tank corrosion.

Fuel quality management is therefore becoming a major consideration, particularly in the fuel distribution business.

Most fuel and oil distributors and operators find that detecting and dealing with the problem by early testing

is an efficient, cost effective answer to managing this risk and there are a number of tests on the market to determine the presence of microbial contaminants, but most require a lengthy analysis period or significant investment in equipment and training.

Conidia’s Fuelstat® Resinae Plus delivers accurate results in 10 minutes and is claimed to be the most “simple to use” test available on the market. No special skills are required, and no investment is needed in readers to translate the results.

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SHALE GAS TO FILL THE ENERGY GAP Given the political and economic factors playing out in the global energy market, the UK Government must prepare for shale gas production, say Daniel Mahoney and Tim Knox of the Centre for Policy Studies

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he current low oil price has led some to question whether UK shale development is economically viable.

This concern would appear unjustified, considering investment decisions will be based on gas prices in the 2020s by which time prices are likely to rise. Moreover, the cost of transporting gas by LNG tanker can add up to 50% to the cost, offering a further reason for promoting UK shale gas development.

The Government must continue to prepare the ground for UK shale development in the 2020s by ensuring that exploratory drilling takes place by the end of this year. More than 80% of UK homes are heated by gas and modelling by the Department for Energy and Climate Change suggests that the UK will need 26GW of new gas capacity by 2030. Without indigenous shale production, around 75% of the UK’s gas will need to be imported.

A sponge that can absorb no more

The global oil market has been likened to a sponge that can absorb no more, and consumers have benefitted from the resulting fall in petrol prices.

Since 2014 the price of oil has fallen from $115 a barrel to around $40 currently, dipping briefly below $30 at times.

This has been driven by supply consistently outperforming demand. Forecasts from the International Energy Agency suggest that average worldwide oil demand for 2016 is nearly 96 million barrels per day with production at around 97 million barrels, leading to a margin of just over 1 per cent.

Although the margin is modest, each day around 1.8m barrels go into storage tanks. The capacity to store oil is now said to be becoming increasingly strained.

The oversupply of oil is primarily being driven by Saudi Arabia’s aggressive geopolitical strategy against US shale •

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producers and Russia. Saudi Arabia has been consistently pumping around 10 million barrels a day for the past few years, and this shows little sign of abating in the immediate future.

Saudi Arabia’s aggressive strategy has been accompanied by a marked increase in US oil production. According to the US Energy Information Administration, the US shale revolution has boosted US oil production by 73% since 2010, tipping the balance on global markets as the US begins exporting.

The lifting of sanctions on Iran will probably further increase global production.

While oil production has increased, global demand for oil has been stagnant, growing by just 1.6% over the past year.

“The countries that need the oil price to rise are those most responsible for its current low price” China’s demand for oil has increased by 3.5% this year despite a broader slowdown in economic growth across emerging economies. This slight increase in demand has, however, failed to keep up with the growing oil supply on global markets.

Politics as important as economics

The current low oil price will begin to make many oil extractions uneconomical. There is already evidence of this occurring. For example, according to the Financial Times, the number of UK North Sea conventional oil rigs has fallen

from 57 to 27, and is likely to fall to just 19 by the summer.

Moreover, the law firm Haynes & Boone claims that 42 oil and gas companies filed for bankruptcy in North America in 2015 – despite there being evidence of major improvements in the productivity of US shale plays. As supply comes off stream, price pressures on oil are likely to emerge.

Furthermore, the current price of oil is not sustainable for the major producers, who rely heavily on income from oil and gas.

The Russian Federation is highly dependent on hydrocarbons, with oil and natural gas revenues accounting for more than 50% of the federal budget revenues. Saudi Arabia’s aggressive geopolitical strategy is also having a detrimental impact on its budget. The Saudi Government ran a record budget deficit of $98 billion, amounting to 15% of Gross Domestic Product (GDP). Saudi Arabia’s government spending as a percentage of GDP leapt from 40.8 per cent to 50.4 per cent from 2014 to 2015, according to the International Monetary Fund.

Paradoxically, those countries that need the oil price to gain in price are those which are most responsible for its current low price: because of the low price, producers such as Saudi, Russia, Nigeria and Venezuela have increased production to make up for their falling revenue. How long this will last is uncertain – and is likely to be as much a political decision as a simple supply and demand equation.

It’s gas prices that matter for the UK

The British Geological Survey estimates that the UK’s potential lies in its unconventional gas reserves, which are mostly located in the North of England’s Bowland region. It is estimated that extracting 10% of the shale could supply the UK with over 40 years of gas supply – although the lack of exploratory drilling means that recovery rates have yet to be determined. The UK’s potential for shale gas means that gas •

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prices are a key consideration of the UK’s shale industry.

Gas prices are linked to oil prices, but it is notable that gas prices have not observed an equivalent decline. In Europe, for example, the EU’s natural gas import price has fallen from a peak of $11.59 per MMbtu in 2014 to $6.24 per MMbtu, which is a fall of 46% compared to oil’s 75%.

The EU’s natural gas import price is high compared to US prices. This is mostly accounted for by the fact that transportation, liquefaction and regasification of gas can add

“99p petrol will not last forever” up to 50% to the wholesale price, according to UKOOG. The Lords Economic Affairs Committee has therefore concluded that, although price cuts are not likely to be as great as those observed in the US, indigenous production of shale is likely to be cheaper than imports of liquefied natural gas (LNG).

The need to prepare for UK shale

Investment decisions relating to UK shale gas will be based on estimates of future prices as much as today’s gas price. It is expected that large scale UK shale gas production will only emerge in the 2020s. As marginally efficient gas supply comes off stream, global gas prices can be expected to rise.

Reducing the UK’s reliance on gas imports would also be beneficial in terms of security of supply. In 2003, the UK was a net exporter of gas – exporting 8m tonnes of oil

equivalent – but in 2015 the UK imported 29 million tonnes of oil equivalent, according to the Department of Energy and Climate Change. It is estimated that without any UK shale development, 75% of the UK’s gas will need to be imported by 2030. Data shows that around 25% of the UK’s gas is currently imported from Qatar – a figure that is likely to increase without indigenous shale production.

The UK will need to make major investments in gas for the 2020s. The UK’s residential heating market is dominated by gas – over 80% of UK homes are connected to the gas grid, according to the Heating and Hotwater Industry Council.

Furthermore, the Government is committed to phasing out coal-fired power stations, meaning that a substantial increase in gas plant is essential to ensure reliable baseload capacity.

Modelling by the Department for Energy and Climate Change suggests that 26 GW of new gas plant will be required by 2030.

Conclusion

Current low oil and gas prices should not be used as an excuse to delay preparations for a growing UK shale gas industry in the 2020s. As outlined above, investment decisions will be based on future prices rather than current ones.

To date, there has been a lack of exploratory drilling and hydraulic fracturing to assess the true potential of shale gas in the UK. The Government must ensure that such exploratory drilling can take place in a timely fashion, so the UK can realise the full benefits of shale.

Exploratory drilling at various sites should begin to take place towards the end of this year and early 2017. It is vital that this drilling takes place so that a true assessment of the UK’s shale can be realised. The Government must ensure that there is no slippage from this timetable.

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osmos Energy’s recent discovery of gas off Senegal and Mauritania represents one of the most significant finds for the West African gas industry in several years, according to Protection Group International Ltd (PGI), but there is significant potential for delay in production as Mauritania and Senegal still need to negotiate ownership of the resource. Uncertainties surrounding oil and gas regulations in both countries may also hold up development, according to PGI’s latest Insight.

the Greater Tortue Complex, where Kosmos is now estimating there are 17 trillion cubic feet (tcf), up from 14 tcf previously.

The discovery is particularly important for the future of oil and gas in Senegal, where more than 140 offshore wells have been drilled since the 1950s but until now proven reserves have been limited.

It may take some time for the development of the SaintLouis Profond to be realised, however. Kosmos announced after the discovery that it had entered into a memorandum

“Complex political debates will mean the Petroleum Code could be subject to long periods of review that could affect project timelines” Kosmos has announced a major discovery of gas at its Guembeul-1 exploration well in the northern part of the Saint Louis Offshore Profond, straddling the border between Senegal and Mauritania. The company made two smaller discoveries off the coast of Mauritania in April and November 2015, and the latest find will raise hopes of further high-quality reserves in 40

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of understanding with Petrosen and Société Mauritanienne des Hydrocarbures et de Patrimonie Minier (SMHPM), the national oil companies of Senegal and Mauritania, in order to develop the field. However, a revenue-sharing formula between the two countries and Kosmos has not yet been finalised.

Kosmos currently holds a 60 per cent interest in the well,

• Insight: Gas discovery

KOSMOS MAKES MAJOR GAS DISCOVERY OFFSHORE WEST AFRICA The biggest gas discovery in West Africa offers a new source of revenue to Mauritania and Senegal, but political problems could hold up development along with Timis Corporation Ltd at 30 per cent and Petrosen at 10 per cent, but it is unclear how Mauritania will benefit from the initiative unless this arrangement is renegotiated. The complexity of the negotiations of gas sharing, of which there is no specific precedent between the two countries, means negotiations could be drawn out and delays are possible. No timeline has yet been set for when these issues will be resolved, leaving the project timeframes vulnerable to complex and politically charged bilateral negotiations.

An unclear legislative framework governing the oil and gas sectors in both Senegal and Mauritania presents further obstacles. Neither country is an established producer of oil or gas and there is little precedent for large scale production. The only case of an oil and gas company reaching production stages in either country involved Australia’s Woodside Petroleum, whose experience highlights the challenges foreign companies can face, in this case in Mauritania. Woodside was involved in production at Mauritania’s offshore Chinguetti oil field in the early 2000s but eventually sold its assets in 2006, saying they were no longer profitable. The sale came after the company was forced to pay $100 million as a “project bonus” to the new Mauritanian authorities, while a separate corruption case by the Australian Federal Police into Woodside’s operations in Mauritania also cast doubt on the project’s feasibility.

The regulatory environment in Senegal presents further uncertainties, at a time when the Senegalese government is seeking to revise its outdated 1998 Petroleum Code. Petrosen has put out a tender for a consultancy to help revise oil regulations in December 2016, with the winning company expected to complete its study within six months. No news has been made public on how the consultancy process is progressing or when a new petroleum code will be delivered, however. Among the key topics of debate are demands from some local regions for greater involvement in decision-making in the oil and gas sector and for the greater allocation of oil revenues.

These complex political debates will mean the Petroleum Code could be subject to long periods of review that could affect project timelines. Presidential elections scheduled for 2017 will further complicate this process and could lead to changes of key personnel responsible for negotiating contracts with companies, as well as those responsible for the revenuesharing negotiations with Mauritania, if those talks continue that long.

PGIs insight on Kosmos Energy’s discovery off Senegal and Mauritania is now available via the PGI Risk Portal. For a free subscription to the Risk Portal visit https://riskportal.pgitl.com/ •

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he first export shipment of liquefied natural gas produced in the Lower 48 states on 24 February is a milestone reflecting a decade of natural gas production growth that has put the United States in a new position in worldwide energy trade.

With the rapid growth of supply from shale gas resources over the past decade, US natural gas production has grown each year since 2006. The resulting decline in domestic natural gas prices has led to rising natural gas exports, both via pipeline to Mexico and, recently, to overseas markets via LNG tankers.

“The US Gulf Coast has a large existing pipeline network, which makes the area attractive for developing export terminals” The United States is currently a net importer of natural gas, and gross imports represented nearly 10% of total supply in 2015, based on data through November. The United States imported 7.5 billion cubic feet per day (bcf/d) of natural gas, mostly from Canada by pipeline, and exported 4.8 bcf/d, mostly to Mexico by pipeline. For years, Alaska has exported LNG, mostly to Pacific Rim countries, but these volumes have been small. In addition to the Sabine Pass terminal that was 42

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the source of the recent LNG shipment, four other LNG export terminals are currently under construction.

When natural gas is cooled to -260 degrees Fahrenheit, it becomes a liquid that is 1/600th of its gaseous volume, making it easier to transport via vessel. The US Gulf Coast has a large existing pipeline network, which makes the area attractive for developing export terminals. Many of the LNG export terminals now under construction or proposed are at sites that have functioned, and may continue to function, as LNG import terminals. Several LNG import terminals were built in the 1970s, and a new wave of terminals was constructed in the mid- to late-2000s. As domestic production increased, LNG imports declined, as many new terminals were barely used and the utilization rates of older terminals declined.

The Federal Energy Regulatory Commission (FERC) is responsible for authorizing the siting and construction of LNG export terminals (as well as import terminals) that are onshore or that are close to the shore. FERC prepares environmental impact statements to assess the consequences of the terminals under its jurisdiction. Although most of the LNG terminals fall under FERC jurisdiction, the US Maritime Administration regulates deepwater terminals. Only one deepwater export terminal has been proposed, and if approved, it would be located about 50 miles south of the Texas-Louisiana border in the Gulf of Mexico.

In addition to approval for construction from FERC or the Maritime Administration, the US Department of Energy’s Office of Fossil Energy issues separate authorizations to export

US BUILDS TERMINALS TO EXPORT LNG As the United States begins to export liquefied natural gas, the US Energy Information Administration reports on the development of its LNG export terminals to countries based on whether they have a free trade agreement with the United States.

Cheniere Energy’s Sabine Pass Liquefaction Project in Sabine Pass, Louisiana, consists of six different liquefaction units, or trains, the first of which began service in February after many delays. The other trains are in various stages of development and permitting. Total permitted capacity by FERC is 4.16 bcf/d.

Four LNG export terminals are currently under construction: • Dominion Energy’s Cove Point LNG facility in Cove Point, Maryland, is scheduled to bring one train totaling 0.82 bcf/d online near the end of 2017.

• Corpus Christi LNG, another Cheniere project, is under construction in Corpus Christi, Texas. The terminal is scheduled to begin service in 2018, with total permitted capacity at 2.14 bcf/d.

• Sempra Energy’s Cameron LNG terminal, located in Hackberry, Louisiana, is under construction and is scheduled to bring three trains online in 2018. A total of 1.7 bcf/d has been permitted.

• Freeport LNG’s terminal planned for Freeport, Texas, has three trains under construction totaling 1.8 bcf/d. The first two are scheduled to begin service in 2019, and the third in 2020.

Another terminal, Southern Union’s Lake Charles (Louisiana) LNG facility, has been approved by FERC but is not yet under construction. Lake Charles also has an LNG import terminal.

Several more LNG export terminals, mostly on the Gulf Coast, have been proposed or have pending applications with FERC.

The new terminals are expected to take advantage of natural gas produced in the Appalachian Basin, particularly the Marcellus and Utica regions, the source of much of the nation’s production growth over the past several years. The Sabine Pass Liquefaction project has secured 300 million cubic feet per day (mmcf/d) of natural gas from the Texas Gas Transmission Ohio-Louisiana Access Project, which facilitates additional

“The new terminals are expected to take advantage of natural gas produced in the Appalachian Basin” flows of Marcellus and Utica natural gas to the southern United States. Additionally, Cheniere’s Corpus Christi Liquefaction project will receive 385 mmcf/d from the Natural Gas Pipeline Company of America’s Gulf Coast mainline pipeline system.

Dominion’s Cove Point (which began operating as an import terminal in 1978) already has a dedicated pipeline with a link to three interstate pipelines that operate in the Marcellus area.

Market conditions have changed since many LNG export projects in the United States were initially proposed. Proposed LNG terminals in the United States face not only increased competition from other domestic and foreign terminals that have been completed, but they also face uncertainty in global LNG demand.

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INTERVIEW Andrew Clifton, general manager and chief executive of SIGTTO (The Society of International Gas Tanker & Terminal Operators) What are the main responsibilities of your job?

The Society is a non-profit making organisation and the international body established for the exchange of technical information and experience between members of the industry, to enhance the safety and operational reliability of gas tankers and terminals.

As general manager I am responsible for the management of the Society and as chief executive I carry out the policies and instructions that are laid down by the board of directors.

I represent the Society, and in effect, the industry, at a senior level at meetings with other professional bodies, members and trade associations such as the International Maritime Organisaton (IMO) and major conferences.

How has your experience in the industry helped?

It’s been invaluable. The liquefied gas industry (and especially the LNG shipping industry) is very different from the rest of the shipping industry. LNG vessels are very complex, capital intensive vessels with a high degree of sophistication built into them. There are also different types of LPG carriers, fully refrigerated, semi-pressurised and fully pressurised and I was fortunate to serve on them all in a senior capacity and also served from cadet to master on gas vessels.

To successfully fulfil this position, it is fundamental that the general manager has extensive experience in the liquefied gas shipping industry.

How does SIGTTO promote best practices and what are the main challenges in implementing them?

The Society publishes studies and produces information papers and works of reference, for the guidance of industry members.

It maintains working relationships with other industry bodies, governmental and intergovernmental agencies, including the IMO, to better promote the safety and integrity of gas transportation and storage schemes.

The LNG industry continues to expand and introduce new technologies. Larger ships with new types of propulsion systems are now in service and the fleet continues to grow apace. FSRUs 44

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and FLNG vessels are now also part of the industry. All these advances ensure that there are many challenges in the liquefied gas shipping and terminal industry today.

Not least of these challenges is the supply of ship crews, shore support staff and trainers to provide the number of trained and competent staff needed in an era of unprecedented growth.

In respect of training the SIGTTO competency standards for crews onboard both LNG and LPG vessels have become the industry best practice recommendation. The standards provide operators with guidance as to the specific competencies each individual should possess before serving in that rank. These standards are above and beyond the minimum requirements of IMO’s Standards of Training Certification and Watchkeeping (STCW) Convention.

How do members benefit from SIGTTO?

Benefits of SIGTTO are substantial, and are not just limited to credibility in the industry. Much of SIGTTO’s work is publicly available but the most important part is not.

Members’ benefit by: • Access to information exclusive to members, such as casualty and industry statistics and lessons learnt • Access to the technical advisers in the London Liaison Office who can give advice and obtain advice, on behalf of a member, from within the Society • Access to the very comprehensive technical library maintained in the London Office • Submitting proposals for industry projects and studies to the General Purposes Committee • Participating in discussion forums, regional forums, and panel meetings with other members • The opportunity to network with members of SIGTTO (over 95% of the LNG shipping and terminal industry and over 50% of the LPG industry are members) • On becoming a member a copy of all publications, free of charge, produced by SIGTTO • Regular updates on matters affecting the industry such as legislation, IMO, either new or pending, technical or

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• Interview • •

operational developments Free access to the LNG webinfo portal for updated LNG information as required.

Do you believe LNG is the “fuel of the future”?

LNG is one of the three choices available to ship owners (scrubbers and distillates being the others) to meet the requirements of the emission control areas (ECA). There is no doubt it is a future fuel for conventional shipping but it is unlikely to happen as fast as some parties are making out. At present, unless your vessel trades exclusively within an ECA, the only reason to change is price. Bunker prices have also fallen and the high capital cost of conversion to LNG has put off a lot of shipowners, plus there is no real infrastructure in operation today to support deep sea vessels bunkering with LNG. This may all change if the IMO goes ahead with the global emissions cap in 2020, the decision will be taken in 2018 – watch this space!

SIGTTO has no doubt that LNG can be safely used as ship’s bunkers but we believe that LNG as fuel should be carried, in principle, with the same designs, procedures, training, control measures and best practices as has been used in the half century of successful LNG vessel operation.

A major incident on an LNG-fuelled vessel, especially one involving passengers, would impact the LNG shipping industry but also have the potential for port and flag states to impose severe restrictions, or even prohibit entry within their jurisdictions, for LNG-fuelled conventional vessels.

The nuclear powered ship Savannah probably has the best emissions record of all time amongst commercial vessels; however it never fully gained the confidence of port and flag states. To avoid supplying potential modern day successors to the Savannah (now a museum ship), it is imperative that the shipping industry embraces the use of LNG as a fuel in the same manner that the LNG shipping industry has.

The Society for Gas as a Marine Fuel (SGMF), which SIGTTO formed in 2013, is the new industry body to oversee the use of LNG as a marine fuel.

What is your position on safety in the industry?

Safety is our licence to operate as an industry. In the 50 years since they loaded their first commercial shipment, LNG carriers have safely delivered over 80,000 cargoes. These consignments all reached their destination with no breach of a cargo containment system and with no onboard fatalities directly attributable to the cargo. This is a very impressive, in fact unprecedented, safety record for the carriage of liquid hydrocarbons by sea in bulk.

This exemplary safety record is due to several reasons. These include, but are not limited to, a strong, overarching safety philosophy; robust equipment and systems design; good operational and maintenance procedures; operating in excess of the minimum requirements and according to best practice guidelines; and high standards of training coupled with competency verification.

Educating the public is extremely important for liquefied gas shipping and the public needs to be made aware that gas carriers are not the “floating bombs” that some scaremongers portray them to be. Public perception is often that an incident on a gas carrier will result in a huge explosion that may harm people and property in the vicinity. The public needs to learn that these vessels are robust ships, soundly designed and constructed and well equipped with safety and emergency

systems. The public also needs to be aware that catastrophic events caused by hydrocarbon gases in the liquid phase are few.

As an example, in a fire accident scenario refrigerated liquefied gas tanks can burn until fuel is consumed but they are highly unlikely to explode.

How important is the International Gas Carrier (IGC) Code to the industry?

Amongst other factors that have contributed to LNG shipping’s remarkable safety record is the fact that the IGC Code was based on actual experiences in the early days of LNG transport and our industry’s ability to share lessons learnt and to develop universally accepted best practices.

Credit also needs to be given to the pioneers who contributed first to the development of design standards and operating procedures during the early days of liquefied gas shipping and then to the development of the IGC Code, with its safety margins and safe design provisions. They played a key role in laying the foundation stones on which the industry’s excellent safety performance has been built.

SIGTTO was heavily involved in the recent revision of the IGC Code and facilitated the revision on behalf of the IMO. The Revised Code was adopted at MSC 93 (May 2014) and entered into force on 1st January 2016. The implementation date is 1st July 2016. It is not retroactively applied and only applies to vessels contracted/ keel laid after 1st July 2016.

What has been most exciting in your career?

I have been lucky enough to have many enjoyable and rewarding periods in my career. I think my seven years as chief officer onboard a first generation 1960s built LPG tonnage was amongst the most challenging but also rewarding, looking back it was invaluable experience although I probably didn’t appreciate it at the time!

Being the LNG shipping manager for a major LNG project (BP Tangguh in Indonesia) was also very rewarding. I oversaw the whole shipping operation from steel cutting through to delivery, commissioning and the first dry docks for seven large time-chartered LNG vessels.

But the greatest honour and privilege I have been asked to do is being the general manager of SIGTTO, an organisation I have been involved with for many years.

Your favourite ship and memorable experience?

I think probably the Excel, built in 1967; one of the first LPG vessels in the world and a challenge to operate when I was chief officer and master on her in the 1990s. Just keeping the vessel safely and efficiently trading with the help of excellent support from ashore was a great example of teamwork and achievement. I do remember the USCG asking where the cargo control room was – there wasn’t one as it was a 100% manual vessel with all operations carried out locally and manually!

Those were the days…

More information about SIGTTO can be found at www. sigtto.org and on Twitter @SIGTTO. Paul González-Morgan Editor, Gibraltar Shipping Email: shippinggib@gmail.com Twitter: @ShippingGib Web: www.gibraltar-shipping.com

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TRUSTING IN TRADE Dr David Blond reflects on a lifetime in economics and observes how the same issues keep coming back to haunt us – like free trade and tariffs

I

wrote an essay for The Manufacturer magazine in July 2002, entitled In Trade We Trust or Should We Trust in Trade?

Rereading it recently, I was struck by how some issues simply refuse to go away. Does this mean that we have failed to find satisfactory ways of dealing with them? If so, why? As the infamous cliché says, if you always do what you always did, you always get what you always got. Is that really where we are still, in terms of global trade and economic policy?

With the United States building up to a Presidential election, and the UK holding a referendum on membership of the European Union, international trade is headline news again.

‘Trade policy’ is a term governments use to describe how they plan to interfere with the natural course of commerce, and it always has a political agenda. President Bush’s introduction of steel tariffs when I wrote the original essay continued a sequence of measures taken by previous presidents to protect key industries.

We all know that economists are a rancorous bunch of academics and intellectuals who cannot even agree on the spelling of Adam Smith. Yet, a recent survey had more than 70% of economists agreeing that free trade is always better than trade protection. How so?

Tariffs are supposed to be a remedy, but they rarely work as advertised. The North American market is too large for that, 48

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and it is also a global price setter. Unless the tax is high enough – 100% or more – most foreign sellers simply adjust their export prices to maintain their market share. Anti-dumping rules take too long to impose and require showing significant harm to the domestic industry, which after a few quarters of facing ruinous competition usually expires long before the President has the

“‘Trade policy’ is a term governments use to describe how they plan to interfere with the natural course of commerce” courage to impose the higher tariffs.

Going to the WTO is an even more difficult task and often triggers retaliation against exports of the complaining country, sometimes in advance of the actual ruling. The WTO is actually the problem, as by design it is a body that blocks efforts by signatory governments to impose solutions unilaterally.

Delays in decisions, often over years, mean that the damage to domestic companies is often fatal and the industry is lost

• Economics

forever. No wonder the world is turning against economists’ solutions for all things complicated – let free markets decide what’s best.

Is free trade always good?

Sometimes, trade friction makes better economic policy for companies and countries alike.

When the yen started to appreciate in the 1980s, Japanese steel producers cut their yen based prices to maintain their dollar prices, so that exports were often loss leaders to maintain market position. Automobile manufacturers did the same.

Cars sold in the US cost less than similar vehicles in Japan, but it was difficult to send a car sold in the US back to Japan because the Japanese drive on the left side of the road, meaning their domestic vehicles have right hand drive. Volkswagen was not able to protect the German car market as well as Japanese companies did theirs, so as the dollar devalued against the Deutschmark in the early 80s, VW exited the US market for nearly 10 years after finding the cost of subsidizing Americans’ purchase of Volkswagens too costly.

In 1981 the US negotiated the Japanese-US auto agreement with Japanese companies, setting voluntary quotas on exports of finished vehicles of a certain size. Two things happened.

Japanese companies built plants in North America (and later in Europe) and replaced their exports of smaller cars (now

built in US) with a new generation of luxury vehicles which earned higher gross margins, so the total value to Japanese exporters of the US market increased. Ultimately, Japanese parts manufacturers followed. Everyone won – US consumers and workers, and Japanese industry, too.

In early 1980, US semi-conductor companies were being systematically excluded from the Japanese market through a series of non-tariff barriers and collusion. The Reagan Administration quietly imposed a series of tariffs on luxury products from Japan. The result was that Japan opened its market to American made electronics for the first time.

The lesson here is that trade friction, caused by barriers rather than open markets, sometimes works to everyone’s advantage, forcing beneficial changes that may otherwise not have happened. Laissez-faire rarely works to resolve imbalances in trade and the unfair practices of trading partners. Sometimes, intervention is a better way, but it matters how it’s managed.

The mining and extractive industries, including oil and gas, face perhaps the most daunting problems with respect to planning for the long term, while having to survive the short-term ups and downs caused by market failures. Unlike manufacturing companies, these two industries have certain advantages as the resources they sell can’t be duplicated everywhere.

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I

ARTS CULTURE

bne November 2015

Let me introduce you to QuERI How can we use QuERI? We are in a transitional period for world trade and for the energy industry from a long period of sustained global growth into a longer period now of uncertainty and incredible structural and technological changes.

What does QuERI include?

Using 72 country specific hybrid IO models, changes in supply and demand for intermediate and final products drives demand for oil, gas, and worldwide transportation.

The collapse of the price of energy from highs of over $100 a barrel to new lows has been brought about by these shifts in both supply and demand balances.

World trade in minerals and manufactures declined significantly in 2015. Forecasting in this environment depends upon understanding the complexity of factors driving demand for individual products.

QuERI models offer more detail on more industries than models commercially available from other vendors.

Global bilateral trade and transport models are also available.

QuERI’s integrated approach to global modelling takes into account changing technologies models based on a stage of economic development approach.

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• Economics

All durable goods depend upon minerals extracted with prices largely determined, unlike drugs or manufactures, by available supplies and demand. Trade barriers against imports of these products are highly unlikely given their importance to the production process, but there are periodic bouts of booms and busts that make planning and investments risky. Extractive industries need good forecasts five to fifty years out, to plan investments especially for hard to reach deposits or difficult to develop oil fields.

“Minerals and oil extraction are the two most profitable or loss making industries in the world” The problem today comes from the misallocation (due to permissive trade policies encouraged by WTO rules against discrimination) of primary processing in a few centers that are prone to slowdown and over capacity. Companies selling extractive commodities assume that demand will remain strong because their sources of supply are so limited. Thus the over concentration of iron ore in Brazil and Australia, combined with the over concentration of iron and steel primary metals production in China, can lead to a bust in exports when this over capacity is recognized.

Given the uneven nature of business collapse—usually sudden,

unexpected, and damaging to the region—markets tend to over react, as they did when they sent iron ore prices down and now back up, as traders start to assess the true nature of the boom and bust in the market for the ores. It is this boom and bust cycle, this shuttering and reopening of facilities, that makes minerals and oil extraction the two potentially most profitable or loss making industries in the world. Yet without continuous renewal of investments in this sector, despite changes in technologies and regulations, global economic growth would stagnate.

In 1972 the Club of Rome, an international think-tank, published its Limits to Growth report, suggesting the world would run out of resources quicker than it could find them.

Its second report was a bit more optimistic, suggesting the catastrophes envisioned in the first report could be avoided.

All of these early studies assumed that we must eventually run out of physical resources – be it land for growing food or minerals and energy resources – limiting our long term potential for growth. Their pessimism was misplaced, as human invention is more powerful than limits to resources.

New reserves can be tapped, but they will not be unless we can place the world on a more sure and even footing, to allow better planning. Until that time, then the extractive industries will remain some of the most risky ventures for companies and yet also the most essential to continuing human progress.

There is no simple answer to the riddle posed by my original title. We are integrated with the world in ways that Adam Smith could not imagine. There is no going back, but there is also no need to go forward with a blind faith in the sanctity of economic theory over common sense.

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• Comment: Drilling

North Sea oil companies must innovate Iain Hutchison, managing director of engineering consultancy Merlin ERD, believes the cost crisis in the North Sea can be solved if oil companies apply innovative solutions

L

ast year Malcolm Webb, CEO of Oil and Gas UK, said UKCS (UK Continental Shelf) exploration was in a “parlous state” and that “we are just not drilling enough wells in UK offshore waters, and those that we are drilling are not finding enough oil and gas. This worrying trend has been growing for some time.”

Scottish-based Merlin ERD designs and drills the longest wells in the world. Managing director Iain Hutchison believes this could be a solution “Over the past seven years our company has developed innovative ‘extended reach drilling’

“I’ve lost count of the number of supposedly impossible wells that we have delivered” technologies which have enabled oil companies to extract oil from places previously thought impossible to reach,” he says. “This solution has been deployed on a global scale and could provide a vital lifeline for the North Sea wells. Extended reach drilling can lower drilling costs, extend field life and increase ultimate recovery of our hydrocarbon reserves. Our technology can exploit reservoirs at 12km and beyond from the wellhead position, often without prohibitively expensive subsea equipment.”

Hutchison is concerned there will be huge consequences if

industry fails to take its opportunities now. “At the moment we stand on a dangerous precipice – politicians are debating while Rome - or should I say in this case Aberdeen - burns. If we lose the fantastic infrastructure that has been built over the past decades it will be lost for a generation and it will be impossible to make up the lost ground.”

In a report to the Scottish Government, it was estimated that the value to the UK of exploiting difficult-to-reach oil could range from $250bn to $1.2 trillion. “If platforms become redundant and offline, a fortune in untapped fuel will be lost,” says Hutchison. “Billions of barrels of oil could be left in the ground. Even before chasing new fields where the payback is much longer, there is a huge opportunity to fully capitalise upon the untapped reserves adjacent to the existing infrastructure. We have only seen the tip of the iceberg in job losses with the inevitable reduction in tax income on which our local services rely.”

The award-winning engineer follows a rich heritage of Scottish engineers and entrepreneurs who would not take no for an answer. “Clever engineering allows existing infrastructure (platforms) to tap stranded reserves on the periphery of their reserves,” he says. “In a true ‘can-do’ approach, our engineers have repeatedly impressed me with their ingenuity at reducing drilling risk, time and cost to exploit hydrocarbon reserves. I’ve lost count of the number of supposedly impossible wells that we have delivered.”

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• Comment: Gas

Unconventional gas is changing global markets

T

he growth of unconventional gas is spreading across the world, with major implications for markets and prices, according to a new World Energy Council study, Unconventional gas, a global phenomenon, which looks at where and how quickly the revolution is taking place.

The study, developed with project partner Accenture Strategy, says that despite an uncertain price environment, the magnitude and speed of change is not only influencing the United States market, but also other markets including China, Argentina and Algeria which have similar potential as the US in shale gas production. Countries such as Mexico, Saudi Arabia, South Africa, Poland and Turkey are also mentioned as having significant potential for shale gas development.

“Unconventional gas is causing a shift in the dynamics of the natural gas market which will be felt for many decades to come,” said Christoph Frei, secretary general of the World Energy Council. “Its spread around the world is being accelerated because it can make gas more affordable to consumers and reduce concerns about the security of supply.

“So far, the surprising resilience of the US shale gas market has led the way in the shale gas boom, and while other countries may not have the unique characteristics of the US, they will learn how to become LNG producers or exporters which will change the global dynamics of energy.”

The study identifies three emerging global trends: • Shifting portfolio allocations: Current price uncertainties are resulting in operators shifting their capital to more flexible, shorter-cycle investments rather than in deep well projects, which is exemplified by the United States.

• International growth of unconventional gas operators: New operators across the world are realising the global opportunities and bringing new supplies to the markets, including China, Australia and Argentina, which will have an effect on markets before 2020.

• Interconnected markets: Excess supplies in some countries have led to price normalisation and other structural shifts that are making the market more global and transparent across the three main regional hubs of Asia, Europe and North America.

Lower oil prices and weakened Asian demand have resulted in the virtual disappearance of the price spread between the Japanese LNG and UK markets in 2016.

Additionally, US prices remain depressed due to the continued build-up of domestic supplies.

Melissa Stark, managing director, energy industry group, Accenture, and co-author of the report, added: “The report emphasises the smooth nature and optionality of the US shale gas supply. The US LNG exports are very different from any supply we have seen before, because this supply can come on-stream very quickly in response to market demand and prices. This LNG supply is driving fundamental changes and commercial innovation in the global LNG market.”

In December 2015, 49 per cent of US gas supplies came from unconventional gas and by 2019 it is predicted that US LNG supplies will account for one fifth of global capacity, making the US the third largest LNG exporter.

For the full report see: https://www.worldenergy.org/ publications/2016/unconventional-gas-a-global-phenomenon/ •

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Saudi aramco where energy is opportunity Producing roughly one in every eight barrels of the world’s oil supply, Saudi Aramco is the world’s largest oil and gas company, with the world’s largest proven crude oil reserves and the largest daily oil production.

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S

audi Aramco is the state-owned oil company of the Kingdom of Saudi Arabia and a fully integrated, global petroleum and chemicals enterprise. Headquartered in Dhahran, Saudi Arabia, with offices and operations throughout the Kingdom, Saudi Aramco employs more than 61,000 workers worldwide across more than 70 countries. The company’s subsidiaries and affiliates are located in Saudi Arabia, China, Egypt, Japan, India, the Netherlands, the Republic of Korea, Singapore, the United Arab Emirates, the United Kingdom and the United States.

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• Saudi Aramco

History

Over the past 80 years Saudi Aramco has become a world leader in hydrocarbons exploration, production, refining, distribution, shipping and marketing, and is the world’s top exporter of crude oil and natural gas liquids (NGLs). The story of Saudi Aramco tells of the discovery and development of the greatest energy reserves the world has ever known and the rapid transformation of Saudi Arabia from desert kingdom to modern nation-state. From its beginnings, Saudi Aramco has grown from an oil-producing company to a fully integrated, global energy enterprise with partnerships in North America, Europe and Asia.

Saudi Aramco has, over the course of its history, built an unmatched record of reliability, and remains committed to providing energy to the world and to maximizing the value of Saudi Arabia’s petroleum reserves for the benefit of its citizens.

From its very beginnings, it has been involved in developing the nation in the broadest sense. During the company’s early years, which were also the early years of the young country of Saudi Arabia, Saudi Aramco’s economic and social service programs became woven into the fabric of the country. Over the years Saudi Aramco began supporting or complementing services increasingly led by the government. Once the company became fully Saudi owned, its social responsibility strategy has become focused on increasing the Kingdom’s revenues from its petroleum reserves and on being a catalyst, a role model and a supporter of growth and development in all aspects of society in general, and in the economic sector in particular.

Business strategy

From producing approximately one in every eight barrels of the world’s crude oil supply to developing breakthrough energy technologies, Saudi Aramco is driven by a core belief that energy is opportunity. As the global population grows, economies •

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Neptune Energy Park

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“Saudi Aramco produces roughly one in every eight barrels of the world’s oil supply”

expand, and standards of living increase, energy will continue to be an essential enabler of opportunity. Saudi Aramco is executing a wide-ranging strategy to ensure that it is at the forefront of providing the required energy for today and for tomorrow. This business strategy has five focus areas.

1. To reinforce its position in oil and gas exploration and production.

Saudi Aramco’s reliability in delivering its products to its customers enables the company to play a leading role in stabilizing world petroleum markets and in ensuring that economies around the world have the energy supplies they need to prosper. Saudi Aramco aims to achieve excellence in every aspect of its upstream operations. This means innovating and applying leading edge technologies in exploration and reservoir management to discover new fields and increase recovery in producing fields. Its maximum sustainable oil production capacity will continue to be 62

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maintained at 12 million bpd while it increases gas production.

Unconventional gas will make a significant contribution in the company’s plans to increase gas production.

2. To integrate the business across the hydrocarbon value chain to create impact.

Saudi Aramco’s greatest opportunities for growth and diversification will come from the steps it is taking to capture and create value from every hydrocarbon molecule. This will open up opportunities for organic growth and strategic partnerships with leading global firms at home and abroad; create more business for service and materials suppliers in local supply chains, and generate new jobs. The expansion of its downstream activities will increase Saudi Aramco’s global presence, creating greater sustainable competitive advantage.

It will better position the company to diversify risk and take advantage of a crude oil placement strategy that provides an optimal balance of geographic exposure between Asia, Europe,

• Saudi Aramco energy, reducing carbon dioxide emissions, realizing more fuelefficient vehicles, creating next-generation materials that make lighter and stronger consumer products and conserving water resources. Such technology targets would overstretch even the best research lab and so Saudi Aramco has adopted an open network innovation model that integrates talent, capabilities, and ideas from around the world. Through research alliances and its global research centers it can create strategic hubs able to grow both in scale and scope.

5. To strengthen its position as an employer of choice.

Saudi Aramco’s ethos of providing the greatest number of opportunities for the greatest number of people ensures that its employees are engaged in meaningful projects with the potential for impact on a global scale. The company’s ability to attract, develop and retain top talent is critical to it achieving its aspirations. It fosters a culture that empowers individuals, encourages collaboration, manages risks, drives accountability, and rewards high performance. This appeals to professionals who are looking for a place where they can work as highfunctioning teams and individuals. Young professionals are particularly drawn to this culture of internal mobility and continuous development, which has increased the young talent in Saudi Aramco’s workforce. Today, almost half of its employees are 35 or younger.

Key projects Manifa

and North America.

3. To enable the sustainable development of the Kingdom of Saudi Arabia.

Though Saudi Aramco is the main driver of the Saudi economy, it leverages its skills and capabilities to expand the opportunities it enables. For example, Saudi Aramco takes on infrastructure and public works projects. It seeks out possibilities at the intersection of its business activities and the Kingdom’s needs, whether by enabling private sector job creation and training, acting as a catalyst for the localization of the Kingdom’s energy services sector, or championing energy efficiency.

4. To lead in technology development and innovation.

People’s lives can be changed for the better by breakthroughs in research domains and Saudi Aramco is working to make reality of ideas like providing more reliable access to affordable

Saudi Aramco has created a giant offshore oil project called Manifa and this one single project has added a million barrels a day to world oil reserves. The development of the offshore Manifa oilfield in shallow water involved the removal of a whole reef and the building of 25 miles of causeway as well as a series of drilling islands. Manifa is one of the largest heavy crude oil increments ever undertaken, and it is considered as the fifth-largest oilfield in the world. Furthermore, the field’s geography - in shallow waters in the fragile ecology of the Arabian Gulf - requires unique, environmentally friendly access solutions involving a novel causeway design linking drilling islands.

Manifa will expand its capacity in the coming year, adding a further 500 million barrels a day to world markets. The project is part of the development of the Saudi oilfields, which are expected to see an increase in production to over 12.5 million barrels a day from 11 million barrels a day. The first phase of the project began production in April 2013. The field produced 500,000bpd by July 2013. It was producing 900,000bpd of crude oil once fully completed by the end of 2014. Additionally, there is production of 90 million standard cubic feet per day of sour gas, 65,000bpd of gas condensate, and water.

Abqaiq

Saudi Aramco’s Abqaiq Plants facility is the company’s biggest oil processing and crude stabilization facility. With a capacity of 7 million barrels per day, the facility is the primary oilprocessing site for Arabian extra light and Arabian light crude oils. The facility handles crude pumped from the Ghawar field and is linked to the Shaybah oil field through a 395-mile pipeline and to the export terminal in Yanbu through a natural gas liquid pipeline. The Abqaiq Plants facility comprises three •

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“Saudi Aramco is working to make reality of ideas like providing more reliable access to affordable energy, reducing carbon dioxide emissions, realizing more fuel-efficient vehicles, creating next-generation materials that make lighter and stronger consumer products and conserving water resources”

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primary processing units – an oil processing unit, an NGL facility and a utilities unit.

“With an eye toward the future, a new project was initiated to increase the crude production of the Khurais facility to 1.5 million bpd, making KhCPF one of the largest oil producing facilities in the world” The oil-processing unit consists of multiple spheroids and 18 stabilizer columns where hydrogen sulphide and 66

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light hydrocarbons are removed from the crude oil. Steam generated by 14 boilers is supplied to the oil processing unit, NGL facility, turbines and compressors. The water treatment plant at the facility comprises 16 reverse osmosis units, which provide demineralized water. The water produced by the plant is supplied as make up to the boilers and heat recovery steam generators to produce the necessary steam. The water produced by the plant is also used as drinking water for plant personnel and is supplied to the neighbouring Abqaiq community. The Abqaiq Plants facility is equipped with two steam-driven and three motor-driven air compressors, which provide the requisite instrument air to operate control valves at the facility.

Haradh

The Haradh Natural Gas and Oil Development lies 280km southwest of Saudi Aramco’s headquarters in Dhahran. The gas plant is capable of delivering 1.5 billion cubic feet a day of sales gas to Saudi Arabia’s Master Gas System and incorporates a gas

• Saudi Aramco

“Saudi Aramco’s ethos is to provide the greatest number of opportunities for the greatest number of people” oil separation plant capable of stabilizing 300,000 barrels per day of Arabian Light crude oil.

The gas oil separation plant associated with the Haradh - also known as GOSP2 - includes a 130 million cubic feet associated gas-gathering facility. In addition to the sales gas, the Haradh Gas Plant is capable of delivering 170,000bpd of condensate to Saudi Aramco’s Abqaiq processing facility and can produce 90t of sulphur a day for export. The plant processes non-associated gas from the wells in the South Ghawar area. The Haradh Natural Gas and Oil Development Project was the third so called ‘mega-project’ completed by Saudi Aramco. About 87 wells feed the Haradh plant. The wells are connected to the plant via manifolds at Haradh, Wagr and Tinat. Sweet and sour gas from the wells is transported through the Haradh manifold, located 12km from plant.

Khurais

The Khurais oilfield development was the largest of several

Saudi Aramco projects intended to boost the production capacity of Saudi Arabia’s oilfields from 11.3 million bpd to 12.5 million bpd by 2009. The Khurais project as a whole covers three oilfields: Khurais, Abu Jifan and Mazalij, with the Khurais field being the biggest in the project.

With an eye toward the future, a new project was initiated to increase the crude production of the facility to 1.5 million bpd, making KhCPF one of the largest oil producing facilities in the world. Planning for the new Khurais increment project began in 2012 and the front end engineering design (FEED) was completed in May 2014.

The current Khurais Program involves the development of the Lower Fadhli field and production to KhCPF, and includes the construction of new processing facilities to handle an additional capacity of 300,000 bpd of Arabian Light crude oil, 143,000,000 scfd of associated gas and 34,000 bpd of NGL. To accommodate this increase, a new gas-oil separation plant (GOSP), a crude stabilization unit and a gas train will be installed at the KhCPF. Two gas turbine driven pump trains will also be installed to provide treated seawater injection for reservoir pressure support.

To optimize energy efficiency and make the plant partially self-reliant with power, a 165 megawatt co-generation unit will also be installed. About 45 percent of the power generated will come from recovering waste heat from the gas turbine hot exhaust flue gases that otherwise would have been vented into the atmosphere.

To comply with Saudi government directives to conserve groundwater, one of the largest membrane technology-based facilities within Saudi Aramco will be installed to use seawater to produce water for process use and refined seawater for injection and enhanced oil recovery production testing.

Shaybah

Shaybah Oil Field is another of Saudi Aramco’s mega projects, a crude oil production site located approximately 25 miles from the northern edge of the Rub’ Al-Khali (Empty Quarter) desert.

Shaybah was developed to exploit the Shaybah oilfield and was developed by Saudi Aramco during the 1990s. Prior to this, only the rough tracks used by early exploration teams existed in this isolated desert region. At the start of the development the Shaybah oilfield had estimated reserves of over 14 billion barrels of crude oil and 25 trillion cubic feet of gas. Saudi Aramco brought the project on-stream in 1998. The crude is Arabian extra light, a high-quality crude grade. The oil pipeline from the Shaybah field to Abqaiq is 638 miles in length.

The Shaybah oil field imposed major challenges during its discovery and development due to the temperatures that soared there to 55° Celsius with heavy dust storms and the shifting sands. Despite the harshness of its climate, the Shaybah field has the best Arabian Extra Light crude oil with a specific gravity of 42 degrees at depth of 4,900 meters.

In April 2011, Saudi Aramco announced its intention to expand the Shaybah field after implementing expansion works that included a fourth plant to double production capacity of the Arabian Extra Light crude oil from 500,000 bpd to 750,000 bpd, besides the establishment of a new plant for gas-oil separation.

The next Shaybah field expansion focuses on two major projects. First is oil production increase by 250,000 barrels per day (bpd), for the second time. The expansion will provide the

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Shaybah field with a capacity of 1 million bpd of Arabian Extra Light crude oil by April, 2016, double its initial capacity in 1998.

“Despite the harshness of its climate, the Shaybah field has the best Arabian Extra Light crude oil with a specific gravity of 42 degrees at depth of 4,900 meters” Moreover, the Saudi oil company is working to improve the design of wells to increase the average reservoir contact to 10 km, enhancing production from the deep, tight faces of the reservoir.

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As for the second project, Saudi Aramco will construct a new NGL plant, to meet the growing demand for petrochemical feedstock through the extraction of high value NGL of the produced gas.

Qatif and Abu Sa’fah

Saudi Aramco is developing the Qatif and Abu Sa’fah fields as a single large-scale project. The Qatif field consists of seven oilbearing reservoirs containing approximately 8.4 billion barrels.

The Abu Sa’fah has reserves of 6.1 billion barrels. The onshore and offshore facilities along the Gulf coast have the capacity to produce, process and transport 500,000bpd of Arabian light crude from the Qatif field, and 300,000bpd of Arabian medium crude from the Abu Sa’fah field, as well as 370 million standard cubic feet per day of associated gas.

The Qatif field is composed of north and south domes. The Qatif gas and oil separation plant gathers gas and 200,000 barrels of crude per day and sends it all to the central

• Saudi Aramco

“Saudi Aramco is developing the Qatif and Abu Sa’fah fields as a single large-scale project. The Qatif field consists of seven oil-bearing reservoirs containing approximately 8.4 billion barrels. The Abu Sa’fah has reserves of 6.1 billion barrels”

processing facility in the north, where the crude is blended with 300,000bpd from the north dome. All the crude is then desalted, stabilized and processed, and shipped to Ju’aymah and Ras Tanura. The gas is sent to the Berri Gas Plant. The development includes three GOSPs (gas-oil separation plants), the installation of five new offshore platforms and upgrading ten existing platforms as well as building 30 drilling islands, constructing 450km of pipelines and 600km of fibre-optic cable and an Industrial Support Facilities Complex consisting of an administration building and maintenance workshops.

Global position

Saudi Aramco’s oil and gas production infrastructure leads the industry in scale of production, operational reliability and technical advances. Its plants and the people who run them make it the world’s largest crude oil exporter, producing roughly one in every eight barrels of the world’s oil supply.

Saudi Aramco maintains the world’s largest spare crude oil

production capacity, ready to stabilize the global oil market in times of disruption. It manages proven conventional crude oil and condensate reserves of 261.1 billion barrels and average crude production is 9.54 million barrels per day. Saudi Aramco also has stewardship of natural gas reserves of 294 trillion standard cubic feet.

Today, Saudi Aramco is positioned to build upon its prominence as a stable supplier of hydrocarbon resources. By producing petrochemical products, building export refineries and advancing the development of technologies that will result in cleaner fuels designed for the new generation of internal combustion engines, it will continue the work of enhancing lives while safeguarding the planet.

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