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Ebara: Transforming wasted energy into LNG

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The Editor

The fuel of the future

Editor

The

Martin Ashcroft

H

aving barely recovered my breath after Offshore Europe 2015, I woke up one day to find myself preparing an issue of Oil, Gas & Shipping for distribution at the Gastech International Conference & Exhibition being held in Singapore, from 27-30 October. Exhibition season is truly upon us.

Gastech will feature over 120 speakers from the global gas supply chain, addressing key issues affecting the upstream, midstream and downstream sectors. I was fascinated to discover the level of competition for speaking opportunities: with around seven applications rejected for every one accepted, delegates can expect a first-class conference programme.

The hot topic, of course, is liquefied natural gas, a growth industry of mega proportions, mainly due to its emission of carbon dioxide being less than other fuels. There is much to be discussed, from quality to pricing to safety to storage and transportation, from environmental compliance to production methods and end use applications. Industry standards also need to be established.

LNG is extremely popular, especially in countries with few energy resources of their own, and transport by ship is

relatively easy. Whether or not those ships themselves might be powered by LNG is a hot topic in itself, as environmental regulations continue to tighten. The world’s first LNG powered containership, Isla Bella, was launched in San Diego in April this year.

In this issue of the magazine Patrick Janssens of ABS (American Bureau of Shipping) discusses the potential use of LNG as fuel and what is involved before shipowners can call themselves ‘LNG ready’. Peter Sand, chief shipping analyst with BIMCO, comments that “a global network of LNG bunkering facilities is needed before shipping can fully embrace and enjoy this new fuel option”.

LNG has been around a long time without its true potential being realised. Construction costs for new LNG facilities are a major issue and an LNG carrier comes in at around $250 million.

In our cover story, however, Ebara advocates the versatility of small-scale LNG facilities.

I have every confidence that many of these issues will move closer to resolution as the result of Gastech 2015. Anything less would be a cryogenic shame!

OIL, GAS & SHIPPING MAGAZINE www.ogsmag.com

3

Contents Page 20

Cover story: Ebara: Transforming wasted energy into LNG

3

15

The Editor: The fuel of the future

AVEVA launches software apprenticeships

News in brief

15

Security fears crippling Yemen upstream O&G

7

d’Amico Int. Shipping orders two more vessels

17

ALE achieve world’s highest jack-up

7

WSS signs agreement to acquire Timm AS

45

Interview: Peter Sand of BIMCO

9

US most attractive LNG suppliers to Asia

50

Turkey: A potential oil & gas hub

11

Resilient energy needs smarter solutions

56

BP Group: Continuing to succeed

ISSUE 84 www.ogsmag.com

7

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LNG ready

The magazine is printed in A4 format on 250gsm gloss laminated cover and 170gsm matt internal pages. The magazine is both a printed hard copy magazine and distributed electronically. Currently our global readership is just over 105,000.

The magazine is also a media partner and supporter of some of the world’s largest exhibitions and conferences.

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Monthly news & features

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All rights reserved. Reproduction in whole or any part without written permission is strictly prohibited. Liability: while every care has been taken in the preperation of this magazine, the publishers cannot be held responsible for the accuracy of the information herein, or any consequence arising from it. All paper used in this production comes from well managed sources.

News and features

News in Brief Ocean freight rates for cargo on the major East-West routes have seen a sharp reduction since the beginning of the year, according to Drewry’s Benchmarking Club. The fall has been driven by a combination of lower fuel costs, excess vessel capacity and intensive competition between shipping lines. Bunker costs have fallen notably since the fourth quarter of 2014 and this has contributed to a reduction in contract rates negotiated since the first quarter of this year.

d’Amico International Shipping orders two more long range vessels

* * *

Hire Torque Ltd has recently signed a distributor agreement with Holmatro of the Netherlands to market its range of hydraulic equipment and systems in the UK. This strategic partnership will ensure that customers are offered the most innovative solutions with Holmatro’s industrial equipment enhancing HTL’s existing portfolio of bolting and flange working solutions. HTL has also been chosen by Weatherford UK as its preferred supplier for torque tooling, services and training through a five year service level agreement. * * * Statoil has chosen Autronica’s Autro Safe integrated fire and gas detection system for its operations in the Johan Sverdrup oil field in the North Sea. The four-year framework agreement is one of the most significant in Autronica’s history, and includes options for two plus two years and for supplying systems to the nearby Johan Castberg, Peregrino and Snorre fields. Installation of the detection systems, which will be developed and manufactured by Autronica in Norway, will begin in early 2016.

d

’Amico International Shipping SA, an international marine transportation company, has announced that its operating subsidiary d’Amico Tankers Limited (Ireland) has entered into an agreement for the construction and sale of two new long range (LR1 – 75,000 DWT) modern product tanker vessels with Hyundai Mipo Dockyard Co. Ltd of South Korea, similar to one already purchased earlier this year. The vessels will be built

by Hyundai Vinashin Shipyard Co in Vietnam and are expected to be delivered in Q2 2018 and Q3 2018 respectively, for a total of around $44.0 million each.

The two double-hull vessels are the latest Eco design with the highest fuel efficiency.

They will have an attained energy design index (EEDI) well within the IMO phasein 2 requirements due for vessels to be built before 31 December 2024, being 25% lower than the current IMO reference line. d’Amico Tankers Limited (Ireland) has 14 new ‘Eco design’ product tanker shipbuilding contracts, which include 6 LR1, 4 MR and 4 Handysize vessels, all under construction at Hyundai Vinashin Shipyard Co. and expected to be delivered

between Q4 2015 and Q3 2018.

“I am very satisfied to announce the exercise of our options to build two further LR1 vessels, in addition to the four units already ordered in April and June,” said Marco Fiori, chief executive officer of d’Amico International Shipping SA. “We reiterate our firm belief in the positive fundamentals of the product tanker industry, which has been giving us further satisfaction even throughout the third quarter of the year, which is usually a weak season for our market.

“Also, I think it is important for DIS to strengthen its presence in LR1s, which I am sure will prove to be a very rewarding segment within our industry, thanks on the one hand to a very low order book and on the other to the expansion of the tonne/ mile demand, following the concentration of the world refining capacity in the US and in the Middle and Far East, away from some of the main consuming regions of the world. In this context, I believe LR1s, with their larger cargo capacity, will be in great demand in the years to come, thanks to their ability to carry larger quantities on the same distances.”

Wilhelmsen Ships Service (WSS) has signed a definitive agreement to acquire Timm AS, a leading provider of high performance ropes. Timm has been in business for more than 240 years and has gained a firm foothold in the merchant fleet, especially in the European market.

Timm is owned by Christian Krefting (through Krefting AS), Jacob Stolt-Nielsen (through BSN AS) and managing director Tore Strand (through Skarbu AS).“We are very pleased that an international and industrial company like WSS will carry on our tradition since 1772 to deliver great

ropes worldwide and grow the business further,” said Krefting and Stolt-Nielsen in a joint statement. “Tore Strand has been instrumental in building up Timm and we are pleased that he will ensure continuity in the leadership as part of WSS.” “This is a renowned brand with high quality products, and a good fit with our global supply and service network,” said Bjørge Grimholt, president of Wilhelmsen Ships Service. “We have significant synergy potential going forward and together we will develop this business in line with our ambitious growth targets.”

* * * Ballast water treatment specialist Optimarin has secured a fleet agreement to install ten of its Optimarin Ballast System (OBS) units in 6,700 TEU container vessels for an unnamed Asian shipowner. The first of the units has already been installed, with two further systems following at the beginning of next year, and two more in spring 2016.

Goltens Green Technology, which entered into an agreement with Optimarin last year as a ‘preferred retrofit partner’, will manage all design and supervision from its Singapore office.

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7

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News and features

US emerges as most attractive LNG supplier to Asian markets

R

ecent reports by the International Energy Agency note that Canada will fail to have any liquefied natural gas export projects up and running before 2020, paving the way for US suppliers to dominate the market.

Goals for British Columbia to secure final investment decision approvals for three plants was deemed highly unlikely, and the report highlighted that the lack of agreement hinged around factors including feedstock gas supply fields and the export terminals being supplied.

Canada is presently competing with LNG projects in the United States that already have the distinct advantage of being developed around existing gas infrastructure, which reduces capital expenditure and makes permitting easier to secure.

New greenfield and established brownfield projects all across the United States are progressing fast with their development towards exports, which most experts agree will amount to more than 60 million tonnes per annum (mtpa) of LNG by the year 2024, making the United States the third largest exporter in the world –

after being a net importer until barely 24 months ago. Opportunities for Canada still remain, however, if it acts fast and the federal government can form a consensus view to grant approval for export projects that could be sited on either the west or east coast of the country.

At the end of this month, the world’s largest gas and LNG event will bring together the project leaders and prospectors developing North American LNG exports to Asia – at the Gastech International Conference & Exhibition being held in Asia’s business epicentre, Singapore, from 27-30 October.

Welcoming 2,000 senior delegates and VIPs, with more than 20,000 exhibition visitors, this is considered the world’s most important event to develop business through the natural gas & LNG value chains and will be critical for both American and Canadian project developers to attend.

As the United States and Canada compete for multi-billion dollar LNG contracts, leading figures from both countries will be present to meet and develop business with major Asian consumers from Japan, Korea,

China, Taiwan, India, and the emerging markets of southeast Asia.

VIPs and leading speakers setting out the case for north America’s LNG supply advantage will include; Robert Franklin, President of ExxonMobil Gas & Power Marketing; Pierre Breber, Executive Vice President of Chevron Gas & Midstream; Governor William Walker, State of Alaska; the Hon. Rich Coleman, Deputy Premier of the Government of British Columbia; the Hon. Michel Samson, Minister for Energy of Nova Scotia; plus a wealth of leading chief executives representing US LNG projects including: Jordan Cove LNG, Annova LNG, Delphin LNG, Texas LNG, Golden Pass and more.

Gastech Conference & Exhibition is hosted by BG Group. The event is also supported by the Energy Market Authority (EMA) Singapore, International Enterprise (IE) Singapore and the Singapore Exhibition & Convention Bureau (SECB), and will be held in association with the Singapore International Energy Week (SIEW).

For further information or to register visit www.gastechsingapore.com/conference OIL, GAS & SHIPPING MAGAZINE www.ogsmag.com

9

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News and features

Resilient energy needs smarter not just stronger solutions

World Energy Council response to extreme weather risks

N

ew approaches are required for the management and financing of energy infrastructures as companies and governments seek to meet the challenges of increased extreme weather risks. “New thinking is needed,” says the latest report from the World Energy Council, The road to resilience: managing and financing extreme weather risks.

The report highlights the need for a move from ‘fail-safe’ systems that only look at single assets to ‘safe-fail’ systems which take a systemic overview of the energy value chain and a more strategic approach to identifying vulnerabilities.

“We are on a path where today’s unlikely events will be tomorrow’s reality,” said Christoph Frei, Secretary General of the World Energy Council. “We need to be smarter and imagine the unlikely.

Traditional ‘fail-safe’ systems, based on predicted events, no longer operate in isolation. New ‘safe-fail’ systems recognise that unexpected weather events are occurring and that systems which go down need smarter, not stronger, solutions. This new approach is essential if we are to cope with new weather

patterns and phenomena such as the more powerful El Niño currently experienced in many parts of the world.”

The World Energy Council report recommends the introduction of new financial instruments such as weather derivatives that complement traditional re-insurance solutions, catastrophe bonds that transfer peak risks to capital markets, and adaption bonds which ensure funds go towards resilience measures, particularly in vulnerable areas.

As average global temperatures over land and ocean surfaces rose to the highest on record for the period January to June 2015, so has the number of global extreme weather events increased over the past three decades, rising by a factor of more than four from only 38 events in 1980 to 174 events in 2014. In 2014 the global insured losses from natural catastrophes and man-made disasters were $35 billion, with uninsured losses in excess of $130 billion.

In North America when Hurricane Sandy hit Manhattan in 2012 the lights stayed out for more than three days. Sandy was the second costliest hurricane in United States history with damage at $75 billion. In early

2015 Chile experienced the equivalent of seven years of rain in 12 hours leaving thousands without electricity. And in the Philippines, the cost of recovery from the 2013 typhoon was estimated at more than double the GDP of the country.

With a shift in the frequency and severity of extreme weather events, their financial impact is also rising, driven by a mix of factors that include economic development, population growth and a higher concentration of people and assets in exposed areas.

The road to resilience: managing and financing extreme weather risks is the first in a series of reports that addresses the need for more investment and system change to combat new emerging risks, including extreme weather, the energy/ water/ food nexus and cyber risks.

The reports are prepared with Swiss Re Corporate Solutions and Marsh & McLennan Companies with insights from the European Bank for Reconstruction and Development.

Send your news to martin@ogsmag.com OIL, GAS & SHIPPING MAGAZINE www.ogsmag.com

11

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News and features

AVEVA launches software development apprenticeship

I

nternational software company AVEVA is launching a new apprenticeship scheme in October 2015, to give young people the opportunity to begin work as software developers in Cambridge, UK. Working with training partner Firebrand, AVEVA will offer a comprehensive higher education Level 4 programme, which involves two years job training and carries accreditation from the BCS, the Chartered Institute for IT. “We have long been supporters of young people entering industry through our graduate opportunities and internships,”

said Hilary Wright, EVP Human Resources, AVEVA. “Not everyone is suited to university education. It is a concern to us that talented potential engineers would miss out on the opportunity of a long and worthwhile career, especially in an area where there is a critical skills shortage. We are delighted that the government has now recognised the need for the software development apprenticeship which gives us the opportunity to offer a highly skilled job role to a young person.”

Skills Minister Nick Boles MP added, “Businesses are better placed than anyone

to train the next generation of workers and will help us deliver three million high-quality apprenticeships by 2020.

By designing apprenticeships, employers like AVEVA are ensuring that young talented people develop the skills needed to progress up the career ladder and help drive businesses forward.”

AVEVA software has enabled the creation of some of the world’s most complex power and process plants, vessels and offshore facilities. Software development apprentices at AVEVA will be able to work on technologies such as AVEVA Everything3D.

Security fears crippling Yemen’s upstream oil and gas industry

T

he continuing deterioration of security conditions in Yemen has led to several international oil companies withdrawing from their operations in the country, with a once-significant source of global supply being reduced to marginal volumes, says an analyst with research and consulting firm GlobalData.

Oil production in Yemen peaked at 441,000 barrels per day in 2001, but this decreased to 125,000 bd in 2014 and is forecast to fall as low as 30,000 bd in 2015. “In 2014, a coalition of tribes took control of the country’s main checkpoints and refused oil companies access to their

fields, significantly impacting operations in Hadramawt, an eastern province which contributed to more than half the country’s oil production,” says Ali AlKillidar, GlobalData’s oil & gas analyst.

The Yemeni government has reported losses from the attacks exceeding $4bn in the past three years. Over 30 oil and gas firms have left Yemen and local inexperienced operators may be left to manage what remains of the industry.

The damage caused to Yemen’s oil and gas infrastructure and industry reputation will take at least five years to return to pre-conflict levels, with production first

expected to arrive from fields with the largest remaining reserves in 2019.

“As of August 2015,” Al-Killidar continues, “of the 13 producing blocks, only the Jannah and Damis blocks were known to be producing. Yemen LNG came online in 2009, and while the country contributed 330 billion cubic feet in 2013, Yemen’s gas infrastructure has been subject to persistent attacks.

“Production became untenable in April 2015, a month after Saudi Arabia started its bombing campaign, when the plant’s operations came to a complete halt after Yemen LNG declared force majeure.”

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News and features

ALE achieves world’s highest jackup and skidding operations

G

lobal heavy lift specialist ALE has completed the 40 metre high jack-up of the Malikai Topside, before skidding the topside a distance of 90 metres at the same elevation - making these the world’s highest jack-up and skidding operations performed on this scale.

The operations were carried out while executing the Malikai EPC TLP Project on behalf of Technip and Malaysia Marine and Heavy Engineering joint venture (TMJV) in Johor Darul Takzim, Malaysia.

ALE was responsible for weighing and transporting four hull block units, living quarters and mega beams for the ‘superlift’ activities. The company was also awarded the weighing and skidding of the topside, jacking-up and skidding at height over the hull and mating the topside with the hull.

ALE began to mobilise the equipment at the beginning of April and started setting up the equipment needed for the superlift (including the computer-controlled skidding system, ALE mast system, mega jack system, weighing cells and strand jacks) in May. The Superlift was then executed in July.

The topside weighed in at 13,800t and

was skidded 85 metres onto ALE’s mega jack system. The mega jack jacked-up the topside to a height of 40 metres - the world’s highest ever jack-up on this scale.

When jacked-up the topside weighed a combined total of 17,300t. It was then skidded a distance of 90 metres at elevation, until it was above the Hull. ALE then mated the topside with the hull.

“The mega jack enabled the client to work on both the topside and the hull on ground level” “It is fantastic to be part of a world first,” commented ALE’s project manager Edwin Blösser, from ALE’s Netherlands branch which coordinated the Superlift activities.

“At ALE we are always willing to push the boundaries to offer a bespoke solution for the client. In order to achieve such an

operation, our engineers and crew have worked hard to carry out the necessary studies and safety checks.

“This Superlift would not have been possible without a great crew and the mega jack system. With its capacity to easily lift the topside to the desired height, the mega jack enabled the client to work on both the topside and the hull on ground level, therefore optimising the logistics needed for such a build. As both the mega jack and skidding systems are operated remotely via a control room and are equipped with computerised controls, which have numerous safety systems implemented, these provided a safe way of working and protected both workers and the client’s equipment being lifted.

“Because the equipment is easy to mobilise and handle, ALE was able to install within the deadline set by the client and despite the challenges ALE faced onsite, the superlift was completed without any delay to the project.”

The final stage of the project will involve the load-out of the tension leg platform (TLP), which is expected to take place later in 2015.

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Transforming wasted energy into LNG In recent years, the demand for LNG throughout the world has increased. This demand is driven by many factors, such as cost benefit, emissions requirements and increasing demand for energy.

One sector in particular, small scale LNG, is evolving rapidly, driven by the increasing demand for LNG fueled vehicles, localized energy production and virtual gas pipelines. As the small scale LNG market increases, new supply chain technologies must be developed to ensure adequate, cost effective supply of LNG. These new supply chain technologies differ greatly from the traditional large-scale liquefaction, distribution and regasification technologies that have been prevalent over the last few decades.

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21

P

erhaps the most important part of the small-scale LNG supply chain is the liquefaction facility. Large-scale LNG liquefaction plants must be geographically located near very large natural gas reserves and sea ports capable of handling large LNG carriers, but small scale liquefaction facilities can be located virtually anywhere a small gas source is available due to their small modular design. These small-scale liquefiers use similar processes as large-scale liquefaction facilities, but at a much lower production rate.

Small-scale liquefiers typically operate in the range of .16 to 966 tonnes (1,000 to 600,000 gallons) per day, compared to their large scale counterparts which can produce upwards of 19,600 tonnes (12 million gallons) of LNG per day. Various thermodynamic cycles are used in LNG liquefaction, including mixed refrigerant, cascade, pre-cooled Joule-Thomson and nitrogen refrigeration.

Although there are significant differences in these technologies in terms of capital cost and operating efficiency, they all share the common process of expanding high pressure, sub-cooled LNG to near atmospheric pressure, saturated LNG. Large-scale liquefaction plants generally use near isentropic cryogenic liquid expanders to perform this pressure reduction, while small-scale liquefiers use almost exclusively isenthalpic Joule-Thomson valves. This article highlights the benefits of applying isentropic 22

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cryogenic liquid expanders in small scale liquefaction facilities to reduce boil off gas production and increase overall liquefaction process efficiency.

Liquefaction process

In order to understand the benefits of cryogenic liquid turbines in the LNG liquefaction process, we must first understand the basic process of gas liquefaction. As previously stated, many thermodynamic processes are used to achieve liquefaction of gasses, however closed loop refrigeration cycles are most common. Figure 1 shows a simplified liquefaction process using a closed loop, mixed refrigerant cycle. This process consists of natural gas and mixed refrigerant gas compressors, a heat exchanger, an evaporative cooler and Joule-Thompson valves.

In this process, a refrigerant (typically propane, or a mixture of hydrocarbon gasses) is compressed to a state above its critical pressure. The flow is then passed through a cooler which rejects the heat of compression to the atmosphere at a near constant pressure. From there the flow is routed through a main heat exchanger, where it is cooled further. Next, the high-pressure refrigerant is flashed over a JT valve in an isenthalpic expansion that lowers its pressure to near atmospheric, and reduces its temperature. This cold, atmospheric pressure refrigerant is then discharged into the main heat exchanger, where the cycle then repeats.

The open loop part of this process that creates the LNG is much simpler. This process consists of compressing clean, dry methane to a pressure above its critical pressure, cooling the stream in the main heat exchanger, then expanding the fluid through a Joule-Thomson valve to near atmospheric pressure. This process results in a liquid/vapor mixture, which is then separated. The liquid portion, LNG, is sent to storage while the vapor portion is recycled back to the gas compressor inlet.

Ebara

Figure 1 OIL, GAS & SHIPPING MAGAZINE www.ogsmag.com

23

Expander basics

Expanders have been traditionally used to generate work by converting a fluid’s internal and kinetic energy into shaft torque.

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

The amount of shaft power produced by a cryogenic expander can 24

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

đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘ Â đ??‚đ??‚đ??‚đ??‚đ??‚đ??‚đ??‚đ??‚đ??‚đ??‚đ??‚đ??‚đ??‚đ??‚đ??‚đ??‚ Â Where:

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

đ??–đ??– = đ??–đ??–đ??–đ??–đ??–đ??–đ??–đ??– đ??Ąđ??Ąđ??&#x;đ??&#x;đ??&#x;đ??&#x; = đ??„đ??„đ??„đ??„đ??„đ??„đ??„đ??„đ??„đ??„đ??„đ??„đ??„đ??„đ??„đ??„  đ??¨đ??¨đ??¨đ??¨  đ??•đ??•đ??•đ??•đ??•đ??•đ??•đ??•đ??•đ??•đ??•đ??•đ??•đ??•đ??•đ??•đ??•đ??•đ??•đ??•đ??•đ??•đ??•đ??•

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

đ??¤đ??¤đ??¤đ??¤

đ??¤đ??¤đ??¤đ??¤

. Inserting this value into equation 1, we get:

đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘ Â đ??‚đ??‚đ??‚đ??‚đ??‚đ??‚đ??‚đ??‚đ??‚đ??‚đ??‚đ??‚đ??‚đ??‚đ??‚đ??‚ Â

đ?&#x;?đ?&#x;? đ??¤đ??¤đ??¤đ??¤ đ??¤đ??¤đ??¤đ??¤ đ??¤đ??¤đ??¤đ??¤ = =. đ?&#x;Žđ?&#x;Žđ?&#x;Žđ?&#x;Žđ?&#x;Žđ?&#x;Žđ?&#x;Žđ?&#x;Žđ?&#x;Žđ?&#x;Žđ?&#x;Žđ?&#x;Ž  đ??¤đ??¤đ??¤đ??¤ đ??Źđ??Ź đ??Źđ??Ź đ?&#x;“đ?&#x;“đ?&#x;“đ?&#x;“đ?&#x;“đ?&#x;“. đ?&#x;–đ?&#x;– đ??¤đ??¤đ??¤đ??¤

From large scale to small scale

Ebara

Historically, the small scale LNG market has operated in a similar manner as the large scale market, where the LNG is sold on a wholesale basis and is used in power generation and other industrial uses. With increasing environmental and financial concerns over the use of other fossil fuels, the small scale LNG market has begun to grow. This new emerging market is taking on a retail sales model where small-scale liquefiers are being constructed to supply individual customers for use as a transportation fuel for LNG powered trucks and marine vessels, local power generation and local industrial use. To support this new demand, new small-scale liquefaction technologies are being developed that produce between 1,000 and 6,000 gallons per day. These facilities are typically small, stand alone plants or may consist of modular components remotely manufactured and assembled on site.

Another difference between the large-scale LNG liquefaction market and the small-scale liquefaction market is the gas source. Large-scale liquefaction plants are built near very large gas reserves that are able to support worldwide import demand. Small-scale liquefiers, on the other hand, can be built or assembled in a fraction of the time near any number of small gas sources such as well heads, gas pipelines, stranded gas reserves and landfills.

Capital and operating costs

When comparing the initial capital costs of small-scale liquefaction, the initial capital costs of large-scale liquefaction are orders of magnitude higher than small scale. On the other hand, the cost per LNG gallon capacity per day is significantly lower.

This is due to higher operating efficiencies as well as economies of scale. The ongoing operating expenses of these different size plants follow the same principal. Large-scale plants are much more complex and operate at higher flow rates, resulting in high operating costs. These same reasons however result in a much lower cost per gallon of LNG produced.

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

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

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

The first step in calculating the reduction in boil off gas is to calculate the power output expected from the cryogenic expander’s electric generator. This is done using the following equation: đ??“đ??“đ??“đ??“đ??“đ??“đ??“đ??“đ??“đ??“đ??“đ??“đ??“đ??“  đ???đ???đ???đ???đ???đ???đ???đ???đ???đ???  đ??Žđ??Žđ??Žđ??Žđ??Žđ??Žđ??Žđ??Žđ??Žđ??Žđ??Žđ??Ž  đ??¤đ??¤đ??¤đ??¤ = Inserting the data above we get:

đ??‹đ??‹đ??‹đ??‹đ??‹đ??‹ Â đ??“đ??“đ??“đ??“đ??“đ??“đ??“đ??“đ??“đ??“đ??“đ??“đ??“đ??“ Â đ???đ???đ???đ???đ???đ???đ???đ???đ???đ??? Â đ??Žđ??Žđ??Žđ??Žđ??Žđ??Žđ??Žđ??Žđ??Žđ??Žđ??Žđ??Ž Â =

đ?&#x;•đ?&#x;•. đ?&#x;–đ?&#x;–đ?&#x;–đ?&#x;– ∗ đ?&#x;‘đ?&#x;‘đ?&#x;‘đ?&#x;‘. đ?&#x;—đ?&#x;— ∗. đ?&#x;–đ?&#x;–đ?&#x;–đ?&#x;– = đ?&#x;“đ?&#x;“. đ?&#x;’đ?&#x;’  đ??¤đ??¤đ??¤đ??¤ đ?&#x;‘đ?&#x;‘đ?&#x;‘đ?&#x;‘

đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘ Â đ??“đ??“đ??“đ??“đ??“đ??“đ??“đ??“đ??“đ??“đ??“đ??“đ??“đ??“ Â đ???đ???đ???đ???đ???đ???đ???đ???đ???đ??? Â đ??Žđ??Žđ??Žđ??Žđ??Žđ??Žđ??Žđ??Žđ??Žđ??Žđ??Žđ??Ž Â =

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đ??Śđ??Śđ?&#x;‘đ?&#x;‘ ∗ ∆đ???đ???[đ??›đ??›đ??›đ??›đ??›đ??›] đ??Ąđ??Ąđ??Ąđ??Ą ∗ đ?›ˆđ?›ˆđ??­đ??­đ??­đ??­đ??­đ??­đ??­đ??­đ??­đ??­đ??­đ??­đ??­đ??­ đ?&#x;‘đ?&#x;‘đ?&#x;‘đ?&#x;‘

đ???đ???[

đ?&#x;?đ?&#x;?đ?&#x;?đ?&#x;?. đ?&#x;‘đ?&#x;‘đ?&#x;‘đ?&#x;‘đ?&#x;‘đ?&#x;‘ ∗ đ?&#x;?đ?&#x;?đ?&#x;?đ?&#x;? ∗. đ?&#x;–đ?&#x;–đ?&#x;–đ?&#x;– = đ?&#x;•đ?&#x;•. đ?&#x;Žđ?&#x;Žđ?&#x;Žđ?&#x;Ž  đ??¤đ??¤đ??¤đ??¤ đ?&#x;‘đ?&#x;‘đ?&#x;‘đ?&#x;‘

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

New cryogenic expander development

In the late 1990s, Ebara International Corporation, Cryodynamics division, developed the first fully submerged, variable speed, cryogenic expander.

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

Conclusion

Cryogenic expanders have been used for almost two decades in large scale LNG liquefaction plants due to their ability to increase process efficiency.

This technology however has yet to be applied to small-scale liquefaction plants. As the previous example shows, by utilizing cryogenic expanders, the operating cost of a small-scale liquefaction plant could be reduced by approximately 4%. This reduction in operating costs typically equates to a payback on the additional capital required to install a turbine between 1 and 4 years, depending on the size of the turbine.

The next step in calculating the reduction in boil-off gas is to apply the results above together with the enthalpy of vaporization of the LNG and refrigerant into equation 1. This results in: đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘  đ??œđ??œđ??œđ??œđ??œđ??œđ??œđ??œđ??œđ??œđ??œđ??œđ??œđ??œđ??œđ??œ  đ??&#x;đ??&#x;đ??&#x;đ??&#x;đ??&#x;đ??&#x;đ??&#x;đ??&#x;  đ??‹đ??‹đ??‹đ??‹đ??‹đ??‹  đ??Źđ??Źđ??Źđ??Źđ??Źđ??Źđ??Źđ??Źđ??Źđ??Źđ??Źđ??Ź  =

đ?&#x;“đ?&#x;“. đ?&#x;’đ?&#x;’ đ??¤đ??¤đ??¤đ??¤ đ??¤đ??¤đ??¤đ??¤ =. đ?&#x;Žđ?&#x;Žđ?&#x;Žđ?&#x;Žđ?&#x;Žđ?&#x;Žđ?&#x;Žđ?&#x;Ž  đ??¤đ??¤đ??¤đ??¤ đ??Źđ??Ź đ??¤đ??¤đ??¤đ??¤

đ?&#x;“đ?&#x;“đ?&#x;“đ?&#x;“đ?&#x;“đ?&#x;“. đ?&#x;–đ?&#x;–

đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘đ??‘  đ??œđ??œđ??œđ??œđ??œđ??œđ??œđ??œđ??œđ??œđ??œđ??œđ??œđ??œđ??œđ??œ  đ??&#x;đ??&#x;đ??&#x;đ??&#x;đ??&#x;đ??&#x;đ??&#x;đ??&#x;  đ??Ťđ??Ťđ??Ťđ??Ťđ??Ťđ??Ťđ??Ťđ??Ťđ??Ťđ??Ťđ??Ťđ??Ťđ??Ťđ??Ťđ??Ťđ??Ťđ??Ťđ??Ťđ??Ťđ??Ťđ??Ťđ??Ť  đ??Źđ??Źđ??Źđ??Źđ??Źđ??Źđ??Źđ??Źđ??Źđ??Źđ??Źđ??Ź  =

đ??¤đ??¤đ??¤đ??¤ đ?&#x;•đ?&#x;•. đ?&#x;Žđ?&#x;Žđ?&#x;Žđ?&#x;Ž đ??¤đ??¤đ??¤đ??¤ =. đ?&#x;Žđ?&#x;Žđ?&#x;Žđ?&#x;Žđ?&#x;Žđ?&#x;Žđ?&#x;Žđ?&#x;Ž  đ??¤đ??¤đ??¤đ??¤ đ??Źđ??Ź đ??¤đ??¤đ??¤đ??¤

đ?&#x;‘đ?&#x;‘đ?&#x;‘đ?&#x;‘đ?&#x;‘đ?&#x;‘. đ?&#x;”đ?&#x;”đ?&#x;”đ?&#x;”

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

đ??“đ??“đ??“đ??“đ??“đ??“đ??“đ??“đ??“đ??“  đ??Ťđ??Ťđ??Ťđ??Ťđ??Ťđ??Ťđ??Ľđ??Ľđ??šđ??šđ??šđ??šđ??šđ??šđ??šđ??šđ??šđ??š  đ??œđ??œđ??œđ??œđ??œđ??œđ??œđ??œđ??œđ??œđ??œđ??œđ??œđ??œđ??œđ??œ =

(. đ?&#x;Žđ?&#x;Žđ?&#x;Žđ?&#x;Žđ?&#x;Žđ?&#x;Žđ?&#x;Žđ?&#x;Ž

đ??¤đ??¤đ??¤đ??¤ đ??¤đ??¤đ??¤đ??¤ +. đ?&#x;Žđ?&#x;Žđ?&#x;Žđ?&#x;Žđ?&#x;Žđ?&#x;Žđ?&#x;Žđ?&#x;Ž ) đ??Źđ??Ź ∗ đ?&#x;?đ?&#x;?đ?&#x;?đ?&#x;?đ?&#x;?đ?&#x;?. đ?&#x;?đ?&#x;?đ?&#x;?đ?&#x;? đ?? đ?? đ?? đ?? đ?? đ?? ∗ đ?&#x;–đ?&#x;–đ?&#x;–đ?&#x;–, đ?&#x;’đ?&#x;’đ?&#x;’đ?&#x;’đ?&#x;Žđ?&#x;Ž đ??Źđ??Źđ??Źđ??Źđ??Źđ??Ź = đ?&#x;?đ?&#x;?, đ?&#x;–đ?&#x;–đ?&#x;–đ?&#x;–đ?&#x;–đ?&#x;– đ?? đ?? đ?? đ?? đ?? đ?? đ??Źđ??Ź đ??¤đ??¤đ??¤đ??¤ đ??Śđ??Śđ?&#x;‘đ?&#x;‘ đ???đ???đ???đ???đ???đ??? đ???đ???đ???đ???đ???đ??? đ?&#x;’đ?&#x;’đ?&#x;’đ?&#x;’đ?&#x;’đ?&#x;’ đ?&#x;‘đ?&#x;‘ đ??Śđ??Ś

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Total: Committed to better energy

Total produces, refines and markets oil as well as manufacturing petrochemicals, and is a major player in natural gas.

Over almost a hundred years, it has expanded its business into more than 130 countries.

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hanks to the unflagging commitment of its employees and investors, Total is now the world’s fourthlargest oil and gas company and second-largest solar energy operator with SunPower.

With operations in more than 130 countries, Total has over 100,000 employees who are fully committed to better energy.

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Readily available energy helps to drive progress. In building a responsible energy future, we must ensure that each individual has access to energy and that energy is used in the most efficient way possible. This is the environment in which Total conducts its business.

Total produces, refines and markets oil as well as manufacturing petrochemicals. It is also a major player in natural gas and ranks second in solar energy with SunPower. Demonstrating their commitment to better energy, its 100,000 employees help supply its customers around the world with safer, cleaner, more efficient and more innovative products that are accessible to as many people as possible. Total works alongside its stakeholders to ensure that its operations consistently deliver economic, social and environmental benefits.

A market leader

The Exploration & Production division is responsible for Total’s oil and natural gas exploration, development and production activities in more than 50 countries. The Gas division unlocks

Gladstone LNG is a leading project in the conversion of coal seam gas (coalbed methane) into liquefied natural gas

Milestones

Total

Total’s story began in the 1920s, with the creation of Compagnie Française des Pétroles (CFP). At the time the company produced oil in the Middle East. Over the years CFP expanded internationally and diversified into refining, petroleum product marketing, and chemicals. In 1929 CFP was listed on the Paris Bourse. It was renamed Total-CFP in 1985, then Total in 1991.

As the 21st century dawned, Total strengthened its position by merging, first with PetroFina and then Elf Aquitaine.

Total’s production activities in the Middle East began in 1924.

In 1929, the company embarked on exploration work in other countries to discover and develop new resources. Its refining activities began the same year, with the creation of an affiliate, Compagnie Française de Raffinage (CFR).

Total started building its chemicals business in the 1960s. At the same time its retail network continued to expand, growing into the global operation it is today. Solar energy was first explored by Total in the 1970s. In 2011 it acquired 60% of the US company SunPower and now owns 65% of what is the world’s secondranking solar operator.

In 1982 Total performed its first deepwater drilling operation (1,714 meters) in the Mediterranean. In 1986 it opened its first automated service station in France and 2011 it created the Total Access network, 600 low-price stations across France. Total plans to open another 150 stations by the end of 2015.

Major projects Surmont Phase 2, Canada: Total’s joint venture with

the value of Total’s natural gas assets. Its capabilities span the liquefied natural gas chain, from liquefaction to shipping and regasification, as well as natural gas marketing.

Refining & Chemicals is a major production hub, with expertise covering refining, petrochemicals and specialty chemicals. Total ranks as one of the world’s ten largest integrated producers.

Trading & Shipping sells Total’s crude oil production, supplies its refineries with feedstock, charters the vessels required for those activities and is involved in derivatives trading. Total is a leading global trader of oil and petroleum products.

Marketing & Services designs and markets a broad array of refined products, including automotive fuel and specialty products such as lubricants, special fluids, LPG, heating and heavy fuel oil, asphalt, additives and special fuels. It also provides services to consumers and to the transportation, housing and manufacturing industries. Total is a leading marketer in Western Europe and the top marketer in Africa. New Energies is helping Total to prepare the energy future by developing its expertise in two core renewable energies, solar and biomass.

ConocoPhillips Canada, Surmont Phase 2 Oil Sands project involves the expansion of the Surmont steam-assisted gravity drainage (SAGD) plant to increase its production capacity from the existing 27,000 barrels of bitumen a day to 136,000 barrels of bitumen a day.

The Surmont site is located approximately 60km southeast of Fort McMurray, Alberta, in the Athabasca oil sands region. It covers an area of approximately 567km². The Surmont Phase 2 project was sanctioned by the partners in January 2010 and construction activities commenced in the same month. It is the biggest SAGD production facility to be built in a single phase. Plans are in place to implement additional phases to further enable the production from the facility to reach an ultimate capacity of 283,000 barrels a day for more than 30 years.

Project activities under Phase 2 will primarily involve the installation of additional well pads, central processing facilities, storage tanks, pipelines and water treatment facilities.

Construction of additional camps, water source and disposal wells, power lines, substation, and roads will also be involved. The terminal expansion project will involve the installation of two 450,000-barrel blend tanks, conversion of an existing blend tank to accommodate diluent, installation of receipt, and distribution manifolds to facilitate transfers to its Waupisoo Pipeline. An upgrade to the associated measurement equipment will also take place.

Gladstone LNG Plant, Australia: GLNG is a

planned liquefied natural gas plant nearing completion in Queensland, Australia. It is a leading project in the conversion of coal seam gas (coalbed methane) into LNG. The GLNG project was announced in July 2007 and will involve piping coal seam gas (CSG) from Santos’ eastern Queensland fields to a plant at Curtis Island off Gladstone, where the gas will be liquefied and loaded to ships for sale to world markets.

The project involves the production of coal seam gas in the Surat OIL, GAS & SHIPPING MAGAZINE www.ogsmag.com

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The Laggan and Tormore fields are expected to make Total the largest producing oil and gas company in the UK

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The gas produced on CLOV will be exported via a subsea line to the onshore Angola LNG liquefaction plant

and Bowen basins in eastern Queensland, which surround the regional centres of Roma and Fairview. Gas will be piped then 435 kilometres (270 mi) to a gas liquefaction plant at Hamilton Point West on Curtis Island near Gladstone, Queensland where the coal seam gas will be converted into LNG. The GLNG project started producing its first liquefied natural gas (LNG) on Curtis Island, Queensland, on 24 September 2015, on schedule and within budget. LNG is currently being produced from Train 1 ahead of the first cargo, which is expected to be shipped to Asian markets in the coming weeks.

Work on the second train is continuing to progress well, with Train 2 expected to be ready for start-up by the end of the year.

Total has a 27.5% interest in the project with Santos holding 30%, Petronas 27.5% and Kogas 15%. Gladstone LNG strengthens Total’s foothold in the Australian market and rounds out its expertise in unconventional gas.

Laggan-Tormore Project, North Sea: Located approximately 125km northwest of the Shetland Islands, the Laggan and Tormore fields represent the future of the UK oil and gas industry. Both fields lie in an area known generically as 36

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West of Shetland – a region geographically closer to the North Atlantic than the North Sea – located on the edge of the UK continental shelf. Here, water depths descend rapidly from an average of 120m to 600m and beyond. It’s a uniquely challenging environment in which to operate, but also one with great potential.

Until today, only oil was recoverable from this harsh frontier area.

Now, with the pipelines and infrastructure Total has built, the region is open to further opportunities in this new strategic hub for the UK. Much of what was previously stranded can now be developed. The £3.5 billion Laggan-Tormore development will add an estimated 100,000 barrels of oil equivalent per day of gas to UK energy supply. Gas will be brought ashore for processing at the Shetland Gas Plant for transporting to the St Fergus Gas Terminal near Peterhead and onward transmission to the National Grid.

Development of the fields was launched in 2010 and first gas is expected in the coming months, at which time Total will expect to become the largest producing oil and gas company in the UK. The development concept consists of a 140-kilometer tie-back of five subsea wells to the new onshore Shetland Gas Plant, with a peak

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production rate of 500 million standard cubic feet per day. Total is the majority stakeholder in this project, which represents exciting challenges for the business.

CLOV, Angola: Developing four fields (Cravo, Lirio,

Orquidea and Violeta), this project comprises 34 wells and 8 manifolds connected by 180 km of subsea pipelines to an FPSO unit at water depths of 1,100 to 1,400 m. Measuring 305 meters long and 61 meters wide, the FPSO has a storage capacity of 1.8 million barrels of oil. The gas produced on CLOV will be exported via a subsea line to the onshore Angola LNG liquefaction plant.

CLOV is a flagship project for Total. It demonstrates the Group’s capacity to successfully start-up projects on time and within budget while mastering cutting-edge deep offshore technologies and keeping safety and environment a top priority. CLOV will contribute to increasing the Block 17 production to 700,000 barrels per day, while also generating significant free cash flow for the Group. Block 17 will therefore become Total’s most prolific production site and bring Total a step closer to achieving its production potential of 3 million barrels per day by 2017.

A subsea multiphase pump system will be used deep offshore to enable production of two different oil qualities from the ssue oligocene reservoirs and the more viscous miocene reservoirs.

A first for Total at this depth, this system will ef be used lastoIl to boost the commingled fluid and enhance oil recovery. The FPSO design minimizes its environmental footprint, with zero flaring under normal operating conditions and an “all electric”confIRm concept lease a to increase on-site energy efficiency by producing only the quantity of electricity required to operate the facilities. As part of Total’s commitment to increasing local content in its projects, a significant part of the CLOV development work was carried out in Angola.

I 108 R :P

P 6 / 5 / 14

Elk and Antelope, Papua New Guinea (PNG): The Elk Antelope LNG field is one of Asia’s biggest potential gas sources. Working together with InterOil, Total’s selection of two key sites to develop Papua New Guinea’s Elk Antelope LNG fields was a difficult task, requiring a full set of studies to reach a decision. The partners in PNG’s second LNG plant have chosen Caution Bay near Port Moresby as the site for the project, while the site of the upstream processing plant will be located near the OIL, GAS & SHIPPING MAGAZINE www.ogsmag.com

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The Elk Antelope LNG field is one of Asia’s biggest potential gas sources

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Purari river in Gulf Province, about 360 kilometres north-west of the capital. The project will be known as Papua LNG. The decision marks a milestone as it allows the joint venture partners to carry out environmental and societal studies, and perform more detailed surveys on each location while working with local communities. The LNG plant at Caution Bay, about 20 kilometres north of Port Moresby, will also maximise the opportunity to pursue potential synergies with the PNG LNG project. Early works are expected to begin in 2016.

environment and culture. It strives to build local capacity in those areas in all its host regions, while introducing development models that can be reproduced anywhere. It cultivates long-term partnerships with private and public stakeholders to achieve those goals. Today, the Total Foundation is France’s largest corporate foundation. Together with Total’s corporate philanthropy projects, its programs represent close to €30 million each year.

Total Foundation

Regardless of the size of any of its projects, Total is committed to protecting the environment and helps communities tackle major social issues. Created in 1992, the Total Foundation implements initiatives in the fields of public health, community support, OIL, GAS & SHIPPING MAGAZINE www.ogsmag.com

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LNG ready Despite the price of oil, shipowners are still ready for LNG as fuel, says Patrick Janssens, VicePresident, Global Gas Solutions, ABS (American Bureau of Shipping)

T

he recent fall in the oil price and its knock on effect to fuel oil has prompted some shipping industry observers to remark that the prospects for growth in the use of LNG as fuel might also be in decline.

The oil price fall might bring some temporary relief to owners who are simultaneously suffering from pressure on freight rates and high operating costs but it is not a signal that alternative fuels are about to fall out of fashion. The belief that a lower oil price might dampen interest in LNG as fuel overlooks the main reason for shipowner interest: the need to comply with environmental regulations.

Owners preferring to stay with conventional fuel must still source traditionally more expensive distillate fuel for SECA compliance. They may also specify a scrubber for SOx compliance but they will need to find a way to comply with Tier III NOx limits, which sulphur scrubbers by themselves cannot deliver.

Whether the oil price stays low for months or years is hard to predict but it should also be remembered that a fall in the oil price also means a corresponding fall in natural gas prices. This may have positive impact in markets such as Asia where gas prices have been higher than in Europe or the US, spurring rather than stalling adoption.

LNG as fuel remains an opportunity to be embraced. Indeed, there can hardly be a shipowner considering newbuilding orders

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LNG ready

The world’s first LNG powered containership, Isla Bella, was launched in San Diego in April 2015

who has not at least considered LNG as fuel in their deliberations.

Some may decide to do nothing – that is a decision in itself – and some are evaluating at what stage in the future they might adopt LNG and for them it is more a question of when than if.

ABS is already providing classification services to newbuilding projects using LNG as fuel and is increasingly helping owners understand what ‘LNG Ready’ means for them as environmental regulations continue to evolve.

At this point it is worth considering what LNG Ready actually means. This has been the subject of a great deal of discussion but owners who want to say ‘I am LNG Ready’ still need a clear definition in terms of class approvals.

ABS has been conducting ad hoc Approvals in Principal for LNG Ready ships for some years. In these cases, the shipowner will define the level of preparedness to be achieved, but each project is different and there has been no consistency between the resulting definitions of LNG Ready and the requirements the owner must satisfy for different degrees of readiness.

ABS has an existing set of rules in its Gas Fuelled Ships Guide and has recently published an LNG Fuel Ready Vessel Guide which defines much more specifically the different levels that can make ships LNG ready. The basic level is the conceptual review which looks at overall arrangement and includes defined layouts for equipment, fuel tank and bunkering and includes a safety risk

assessment. The second level is a general design review, the main aim of which is to make sure that when an owner takes delivery they will have a conversion design package that is approved by their class society.

This means that should they decide to convert in future they are able to approach a conversion yard with an approved package. This also reduces the potential headache for the owner since their technical staff and superintendents are unlikely to be gas experts, but can use the class approval as a basis for the conversion.

The third level applies when an owner decides to install some of the equipment and includes a class notation for those elements – typically fuel tank foundations, the fuel tank itself or piping systems. Approval in this case includes a detailed design review so that when an owner decides to convert the ship will require an additional survey rather than fresh approval.

ABS is already providing classification services for newbuildings that will use LNG as fuel and the level of interest around LNG Ready vessels can only continue to grow as the number of ships affected by regulation increases.

Shipowners are increasingly recognising that classification societies have the specialist knowledge to support them as they evaluate what LNG Ready means and how to prepare for that future.

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Interview: Peter Sand, Chief Shipping Analyst, Baltic and International Maritime Council (BIMCO) Peter Sand joined BIMCO in 2009. With a master’s degree in economics from the University of Copenhagen he is responsible for analysing the commercial markets for dry bulkers, tankers and containerships.

What do you enjoy most about being chief shipping analyst?

Having the whole world as my playground! As an economist now working in shipping, I am spoiled for choice every day as to what to analyse. So many things are happening in so many different countries.

Your market reports are highly regarded by the shipping community. How do you manage the different sources of information and their veracity?

An integral part is to always stay abreast with who provides quality information. We continuously evaluate our sources.

Building a report or a market comment always starts with something happening on the global macroeconomic side of things, or a pure shipping event that we would like to know more about because it affects the market. For our quarterly Shipping Market Overview & Outlook we start our work on the supply side. Getting the data from either of the two major fleet data suppliers, in a raw format. Then we add our market insight and understanding of the dynamics of the order book and of how the data is compiled by the supplier.

As shipping lines continue to open more trade routes in Africa, what advice would you give to companies considering this as part of their business plan?

Africa provides a wide array of opportunities. This goes for dry bulk, containers and tankers as well as the more specialized parts of shipping. In the maritime sector, industry relationships are important, so if you want to do business in Africa tomorrow you should start to work on your relationships today.

Currently, Africa as such is not a big market, if you look beyond some specialized trade and the all-important sweet crude oil exports out of West Africa. A futurist once told me not to underestimate Africa, and I certainly wouldn’t do that, but to put it into perspective, the entire African continent has a GDP about the same size as Italy. We need to be a bit further down the road before Africa becomes a driver in the shipping market. Until then, we will monitor the developments closely.

What are the current options for shipping lines looking to finance vessel acquisitions?

We have just passed the 7th “anniversary” of the Lehman Brothers crash. That event changed everything, including ship financing. Before the crisis, it appeared as if banks and other lenders did not put the right price on risk, meaning that you could obtain the same conditions regardless of whether your new build would go directly into a 10-year time charter with an OIL, GAS & SHIPPING MAGAZINE www.ogsmag.com

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“A global network of LNG bunkering facilities is needed before shipping can fully embrace this new fuel option”

A-rated financially rock solid counterpart or trade fully in the spot market at its mercy.

Today, the price-setting of risk has “normalised”. Many of the lenders now have to hold higher reserves if they want to lend out to shipping interests, due to regulations like Basel III, as well as a more cautious approach to shipping lending, as banks attach a higher risk to the shipping industry today than before. This means financing is more expensive and more difficult to get.

In theory, this development has resulted in ship owners seeking financing elsewhere and there are many options to choose from, i.e. bond issues, private equity, export credit agencies etc. Bank lending remains the preferred option, however, as fewer strings are attached it.

While financing is more difficult to obtain today, you cannot say those difficulties have resulted in a significantly lower number of new build orders.

What are the key variables affecting shipping freight rates in the current market?

It is the same “2 times 5” fundamental variables that have always affected the freight rates. On the demand side we have world economy, seaborne trade, average haul, random shocks and transport cost. On the supply side we have world fleet, fleet productivity, shipbuilding production, scrapping and freight revenue – all in order of importance.

Certainly, we have a “new normal” in shipping, but that only means that we have to get used to slower growth rates and adapt to that in our decision making.

In terms of the freight rate mechanism, an oversupplied market finds its equilibrium freight rate on the elastic part of the supply curve. An example of this is the current dry bulk market. Only 46

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when all ships are in service and operate at a more normal speed level does the supply side become inelastic and freight rates become very sensitive to changes in demand. An example of this is the current crude oil tanker market.

LNG is considered by many to be the fuel of the future. What are your views?

In 1912, M/S Selandia marked the beginning of a new era in shipping as it was the first large diesel-powered ship; until then coal-burning steam ships had been used. Nevertheless it took many years for the merchant fleet to become fully diesel-powered.

Some of the reasons for that we also see today for one of the fuels of the future – LNG. First and foremost, availability is key.

I know that Gibraltar is committed to add LNG bunkering to its already wide pallet of services to industry, and a global network of LNG bunkering facilities is needed before shipping can fully embrace and enjoy this new fuel option.

Beyond the pioneering environment of Scandinavia, I believe we are going to see this develop along the liner trade lanes first.

Later, tramp shipping will join in, when LNG bunkering becomes more widely available. It is still premature to say when we will see LNG being offered to the shipping industry as a fuel next to oil bunkers everywhere. That’s why remembering M/S Selandia puts things into perspective – eventually it will happen.

What are your thoughts on Gibraltar as a shipping centre?

It’s a unique location where the Med meets the Atlantic, in the middle of continents and trading lanes and a shipping centre with more and more services being added as we go along.

Gibraltar has the fundamentals in place to become an even more important player in the market in the future.

Interview: Peter Sand

What attracted you to the shipping industry in the first place?

I love economics and geography and have a general interest in understanding what goes on in the world. In our industry these are central pillars. I also realised quickly that our industry attracts all kinds of people from all kinds of backgrounds from all over the world. We have adventure in common. Having spent a decade in shipping, I take pride in being a part of the global family that our industry truly is.

As well as being an analyst, you also teach maritime trainees.

How important is training and development in this industry?

I would say it’s all-important. For seafarers as well as landlubbers.

Knowledge needs to be passed on to the next generation of shipping people. BIMCO has a lot of family-owned businesses in our membership and for them passing on a lifetime of experience and know-how to the sons, daughters and other relatives or partners is essential.

But they can only pass on so many things. BIMCO assists with “all the rest”. Be it technical guidance, contractual knowledge, education or our vast database of information, the BIMCO staff is ready to service members across the shipping industry.

Your favourite book?

As a professional it’s Stopford’s Maritime Economics. You take something new from it you every time you read it. As a private individual – I am a sports fan, crazy about motorsports, football and cycling. Right now I am speed-reading the memoires of a life on a bicycle, by the former cycling professional with Team Telekom etc, Brian Holm. The book is called Enjoy the pain (Originally: Smerten - glæden). Full of humour and insights from an enclosed world.

After reading his more recent book this summer, which was focused on his year of ups and downs, as sporting director with HTC Highroad in the year 2011, ending with Mark Cavendish becoming the World Road Cycling Champion and the dissolvent of HTC-H team, I needed more – and I got it.

Your favourite ship?

As a professional it would be the Panamax dry bulk carrier Nord Navigator. She took me on a journey from Hamburg to Sveagruva on Svalbard in November 2014. This was a huge experience and it brought me a richer picture of the entire industry. I enjoyed extraordinary hospitality on board as I got to know the entire crew during their daily work. Admittedly, we did also share a few songs on the karaoke machine. Wonderful people. In many ways this journey also epitomises what shipping is all about – relationships. Thanks to my former colleagues at D/S Norden for given me this opportunity and making it happen.

As a private person, it would be my kayak, or rather my kayak clubs. This summer I took my license to prove I had obtained the basics of how to handle such a “ship”. Being on the water as a rookie, you need to be fully focused. If you’re not, you’ll end up in the lake. During my training I earned the nickname: “pool attendant”; I guess it was due my multiple capsizing. Today I normally stay in the kayak.

Paul González-Morgan Editor, Gibraltar Shipping Email: shippinggib@gmail.com Twitter: @ShippingGib Web: www.gibraltar-shipping.com OIL, GAS & SHIPPING MAGAZINE www.ogsmag.com

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Turkey: A potential oil & gas hub Ozan Karaduman and Direnç Bada of Istanbulbased law firm Gun + Partners examine Turkey’s potential to become a global oil & gas hub

T

urkey is a country almost barren of oil and natural gas resources. Its production is minimal when compared to its hydrocarbon rich neighbours such as Azerbaijan, Russia, Iraq and Iran. Although recent exploration activities suggest a potential in terms of oil and natural gas, Turkey is not expected to be an important oil or natural gas producer in the short or even mid-term.

Although Turkey does not have the natural resources of its neighbours, it still has a specific advantage, however.

It is located between the oil rich countries and the highly industrialised western economies which are large oil and natural gas consumers. Turkey bridges the gap between the energyhungry West and the energy-rich East and is a connection point between the supply and demand of oil and natural gas. However, at present Turkey does not actually connect this supply and demand and does not currently use its potential.

Throughout history, oil and natural gas have never been separated from politics. The recent problems with Russia accelerated Europe’s searches for alternative sources of supply and Turkey has now become their principal focus. With the 50

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outstanding strategic importance its geographic location plays, Turkey is considered to be essential for the future of Europe’s energy security.

Currently, crude oil and natural gas are carried via land pipelines to and within Turkey from countries such as Russia, Azerbaijan, Iraq and Iran. Crude oil is then transferred to oil tankers at the end-points of the oil pipelines destined to go to refineries in Turkey or abroad. Natural gas is mostly fed-in to the national transmission infrastructure for domestic consumption except for the Turkey-Greece pipeline which feeds the Azeri natural gas to Greece. In exceptional circumstances, it is also possible to transport crude oil via road or rail. However, this article will focus on the transportation of oil and natural gas into and out of Turkey via pipelines and Turkey’s efforts to develop the pipeline projects to become an energy hub in its region.

Legal framework The main legislation for transporting oil and natural gas through pipelines is the Law on Transit Pass of Oil through Pipelines dated 23 June 2000 (Pipeline Law). The Oil Market Law dated 4

December 2013 and the Natural Gas Market Law, 18 April 2001 are also relevant as these laws regulate the transmission and transportation of oil and natural gas within Turkey. Finally, the Decree on Transportation of the Crude Oil and Jet Fuel via Road or Railway published in the Official Gazette dated 11 November 2011 (Decree) is of importance as it prohibits the import, export and transit of oil through roads and railways unless a specific

“Turkey bridges the gap between the energy-hungry West and the energy-rich East� permit is obtained for such actions. The permit is obtained from the Ministry of Customs and Trade (MCT) only in cases

where the importation, exportation or transit of oil via roads or railways is beneficial to the interests of Turkey.

In addition to the exceptional cases of transport by road and rail, oil and natural gas can be transported by sea. However, pipeline projects are preferred instead, since they have the ability to transport larger amounts of oil or gas, reduce the risks involved and ensure better accountability. Although this type of project requires considerable capital, it is nonetheless the economically most favourable method overall.

The Pipeline Law aims to regulate the main principles and procedures of pipeline projects and for many issues it leaves room for the regulations of international treaties signed/to be signed for construction and operation of such pipeline projects.

This is a practical approach as a pipeline project can cover many countries and it would not be wise to regulate all the issues related to such a project with a domestic law. The Pipeline Law mainly sets the principles regarding the local part of the pipeline projects such as how the expropriation will be made, how the security of the pipeline will be maintained, whether insurance for third party liability is required, etc.

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Article 6 of the Pipeline Law states that the security of pipelines will be maintained by the state security forces and Article 10 requires that a third party insurance policy be made to cover the losses of any third party arising from the pipeline.

Completed oil pipeline projects Although Turkey has not maximised its geographical potential to be an oil and gas hub, this does not mean that the country has not made any progress, however. Turkey currently has a number of completed international oil and gas pipelines which are operational and is developing new pipelines.

The Baku-Tbilisi-Ceyhan Crude Oil Pipeline Project (BTC) came from an agreement between Turkey, Azerbaijan and Georgia and was approved by the Turkish government in June 2000. This is a 1,768-kilometer-long crude oil pipeline connecting Baku, the capital of Azerbaijan, to Ceyhan via Tbilisi in Georgia.

The oil coming out at the end-point in Ceyhan is shipped around the world by oil tankers. The first batch of oil was transported in 2005 and arrived in Turkey in 2006. From then to the end of 2014, 2.1 million barrels of oil have been carried around the world from here.

The Turkish Petroleum International Corporation (TPIC) owns 6.53% of the project. The Azerbaijan and Georgia sections of the pipeline are operated by BP on behalf of its shareholders in the BTC company, while the Turkish section is managed by BOTAŞ International Limited (BIL).

The Iraq-Turkey Crude Oil Pipeline Project was the result of a 1973 agreement between Turkey and Iraq and approved by the Turkish parliament in March 1986. This pipeline connects Kirkuk to Ankara. The stored oil is shipped around the world. In 2014, it was recorded that 55.9 million barrels had been carried through this pipeline. Because of the problems in Iraq, however, Turkey has not benefited from this pipeline to the extent originally expected.

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Completed natural gas pipeline projects The 1,213 kilometre Blue Stream Natural Gas Pipeline Project was agreed between Turkey and Iraq and approved by Turkish government in May 1998. Blue Stream carries Russian gas to Turkey through the Black Sea. The Russian section is owned and operated by Gazprom, while the Turkish section is owned and operated by BOTAŞ. Italian Eni acted as a key partner involved in the project, especially during the construction period. The first gas supply was transported in 2003.

The Baku-Tbilisi-Erzurum Natural Gas Pipeline Project was approved in December 2001. The project was built in parallel to and with the same principles as the BTC Crude Oil Pipeline project, and carries Azeri gas to Turkey. The first delivery was received in 2007 and the agreement is presently in force.

The Interconnector Turkey-Greece-Italy (ITGI) Pipeline was approved in 2004 and carried its first delivery in 2007. The 296 kilometre ITGI Pipeline carries Azeri gas to Greece from Turkey and is recorded to carry 705 million cubic meters per annum.

There are plans to extend the project to Italy, although there are no specific developments on that yet.

The Tabriz-Ankara Pipeline is the result of an agreement between Turkey and Iran to carry Iranian gas originating from Tabriz to the Turkish capital Ankara, through Anatolia. This pipeline has a potential to transport 10 billion cubic metres per annum.

Ongoing natural gas projects The TANAP Natural Gas Pipeline Project was agreed between Turkey and Azerbaijan in June 2012 and approved by theTurkish Parliament in January 2013.

The primary goal of the TANAP Project is to deliver natural gas produced in Azerbaijan’s Shah Deniz-2 gas field and other areas of the Caspian Sea, primarily to Turkey, but also to Europe. TANAP will run through 20 provinces in Turkey until it reaches the end of

Turkey: A potential oil & gas hub

its course at the Greek border in the Ipsala district of Edirne.

TANAP constitutes part of the Southern Gas Corridor along with the South Caucasus Pipeline (SCP) and the Trans-Adriatic Pipeline (TAP). The TAP will connect to this pipeline to convey natural gas to European states, initiating at the Greek border beside the Ipsala district.

TANAP will secure the delivery of gas to European markets, while also satisfying the growing demand for natural gas in Turkey. The State Oil Company of the Azerbaijani Republic

Turkey is heavily dependent on Russia for natural gas and needs an alternative source (SOCAR) holds 58 per cent of the total stak The country is heavily dependent on Russia for natural gas and needs an alternative source es, while the state-owned Turkish company, BOTAŞ, holds 30 per cent. Construction of the project began on 16 March with the attendance of the Presidents of Turkey, Azerbaijan and Georgia.

The Turkish Stream Pipeline is a proposed project to transport Russian gas across the Black Sea to Turkey and the rest of Europe. The proposal was announced by Russian president Vladimir Putin on 1 December 2014, during his state visit to Turkey and is expected to replace the South Stream Pipeline project.

The planned capacity of the pipeline is to carry 63 billion cubic meters of natural gas per annum. This would mean that Turkey would receive about 14 billion cubic meters per annum, while the rest of the gas transported is planned to be exported

to Europe. The negotiation process between Turkey and Russia, however, is currently suspended.

Conclusion Currently, Turkey is neither a corridor nor a hub for oil & gas but the potential of becoming a corridor or even a hub is there.

Turkey has every reason to develop new pipeline projects; despite the financial turmoil, its economy continues to grow which results in greater consumption of oil and gas. The country is heavily dependent on Russia for natural gas and needs an alternative source. Its oil rich neighbours Iraq and Iran are both more than willing to supply it.

Europe’s oil and gas consumption increases constantly and Russia’s gas supply plays an important role for that demand as well. It is no secret that Europe also searches for an alternative.

The barriers for taking Iranian gas and oil will hopefully be revoked for good as a result of the nuclear agreement, which will create an important source of supply. Iraq has the potential to be an even more important supplier if the issues between the northern regime and the central government can be resolved and the risks of war are reduced.

Turkey’s domestic needs and Europe’s requirements for alternative sources of supply create an excellent potential for the development of new oil and gas pipelines crossing the country.

Turkey needs to aim not only for transition fees but also for enabling off-take stations within Turkey and for ownership rights over a considerable capacity so it can overcome its lack of oil and gas resources, begin to use its geographical potential and establish itself as an oil and gas hub.

Ozan Karaduman is managing associate and Direnç Bada a trainee associate at Istanbul-based law firm Gun + Partners OIL, GAS & SHIPPING MAGAZINE www.ogsmag.com

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Clair Ridge Installation QUID & GM modules- BP PLC 56

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BP

Group: Continuing to succeed Oil and gas giant BP, with its global workforce of more than 83,000 people, continues to be an innovative force in today’s marketplace and one project more than any other highlights this – Clair Ridge.

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BP Group

C

Clair Ridge GM & LQ modules onboard Dockwise Mighty Servant- BP PLC

lair Ridge is a £4.5 billion investment in the second phase of development on the Clair field, which lies 75km to the west of the Shetland Islands. The project will comprise two new bridgelinked platforms, as well as new pipeline infrastructure to connect to processing facilities on Shetland. Production from Clair started in 2005 from the first phase facilities, which are designed to continue producing until 2028. About 80 million bbl have been produced thus far. Oil and gas is exported via pipelines to the Sullom Voe terminal on Shetland where it is processed. Full production is expected to commence in late 2016.

The Clair reservoir was first discovered in 1977. In the 1980s ten appraisal wells were drilled. This activity demonstrated that the structure extended to an area of some 400 square kilometres (150 sq mi) with static oil-in-place, although it failed to confirm the presence of economically recoverable reserves. Two further wells were drilled in 1991, two in 1992 and one in 1995.

In 1996 there was a breakthrough in the drilling and extended well testing (EWT) of one well. The EWT was followed by the side-tracking of an offset well into the pressure sink created by the EWT. The 1996 well test results set the scope for the 1997 drilling programme and triggered interest in a first phase of development.

Two further wells were drilled in 1997 to appraise the ‘Graben’ and ‘3A’ segments to reduce uncertainty in these areas adjacent to the core area.

In May 1997 it was agreed by the Clair partners to jointly develop the field. BP was appointed as the operator and programme coordinator. A development plan was approved 58

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in 2001, representing an investment of £650m by BP and its partners, ConocoPhillips, Chevron and Shell, in the project. The production facilities were installed in 2004. The first stage of the development was inaugurated on 23 February 2005.

The project primarily involves the installation of two bridgelinked platforms at a water depth of approximately 140m, the drilling of 36 wells (26 producing wells and 10 water injectors), and a tie-in to the existing Clair Phase 1 export pipeline system.

The platforms will include a drilling and production (DP) platform and a 9,000t quarters and utilities (QU) platform. The installation of the DP and QU steel jackets weighing 22,300t and 9,000t respectively was completed in August 2013, while the topsides are expected to be installed late in 2015. Initial drilling works for the project include the pre-drilling of seven wells using an eight-slot subsea template with the help of a semi-submersible drilling rig. The remaining wells, on the other hand, will be drilled by the DP platform over 12 years.

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The project involves the installation of two bridge-linked platforms at a water depth of approximately 140m, the drilling of 36 wells and a tie-in to the existing Clair Phase 1 export pipeline system

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BP Group

Clair Ridge Installation- LQ module approach- BP PLC

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Clair Ridge InstallationLQ module- BP PLC

“In Norwegian tradition the platform jackets have been formally named. The largest is called Odin, after the most powerful Norse god.

The smaller jacket has been named Frigg - Odin’s wife” The produced oil will be exported to the Sullom Voe Terminal (SVT) via a new 6.5km long and 22in diameter pipeline connected to the existing Clair Phase 1 oil export pipeline, whereas the produced gas will be exported to the SVT via a new 14km long and six inches diameter pipeline connected to the west of the Shetland pipeline system.

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In August last year BP and its co-venturers confirmed the safe installation of the Clair Ridge platform jackets, a major milestone in the Clair Ridge project. The platform jackets were made at the Kvaerner yard in Verdal, Norway. In Norwegian tradition they have been formally named. The largest is called Odin, after the most powerful Norse god, reflecting the size of the jacket. The smaller jacket has been named Frigg - Odin’s wife.

In June this year BP announced the safe installation of the new Clair Ridge platform’s quarters and utilities (QU) topside modules, and so another milestone is achieved. The QU platform comprises three modules—the quarters and utilities integrated deck (QUID), which has a lift weight of 9,400te; the power generation (GM) module, which has a lift weight of 4,550te; and the living quarters (LQ) module, which has a lift weight of 2,210te. They were safely lifted onto the pre-installed jackets by the Heerema Thialf heavy-lift vessel.

“The safe installation of these three topside modules is a fantastic

BP Group

Clair Ridge quick facts Clair Ridge is a £4.5 billion investment in the second phase of development The Clair reservoir was first discovered in 1977 BP was appointed as the operator and programme coordinator in May 1997 The installation of the DP and QU steel jackets was completed in August 2013 The Clair Ridge development will be able to produce an estimated 640 million barrels of oil over a 40-year period, with peak production expected to be up to 120,000 barrels of oil per day The produced oil will be exported to the Sullom Voe Terminal via a new 6.5km long pipeline connected to the existing Clair Phase 1 oil export pipeline

achievement by the project team,” said Trevor Garlick, regional president for BP’s North Sea business. “In a challenging time for the industry, this project shows the potential of our basin and why it is so important that we work to ensure a competitive future business.”

BP describes Clair Ridge as the first sanctioned large-scale offshore enhanced oil recovery scheme using reduced salinity water injection to extract a higher proportion of oil over the life of the field. To reduce the environmental impact of the project, the platforms will be powered using dual-fuel power generators, incorporating waste heat recovery technology. Vapor recovery will also be used to capture and recycle low pressure gas for use as fuel or for exporting to shore.

The Clair Ridge development will have the capability to produce an estimated 640 million barrels of oil over a 40-year period, with peak production expected to be up to 120,000 barrels of oil per day. The project is headquartered in London, where over 750

people are currently employed.

About 30% of the £2.1bn base cost of the project is in the UK and around 80% of the estimated £1.1bn of drilling costs will be spent in the UK. More than 80 British companies are providing engineering design and support services, hook up and installation services, manpower and a wide range of engineered equipment.

A project of this size and longevity requires secure, long-term partnerships and BP has made use of its extensive network of suppliers and subcontractors, to ensure Clair Ridge meets cost and timeline targets.

In addition, BP has been able to recruit an additional 600 staff internally, including offering new engineering apprenticeships.

Other projects

Clair Ridge is a flagship project, but it’s not the only one. Other significant upstream projects include Kizomba Satellites 2, In Salah Southern Fields, Greater Plutonio 3, Western Flank A, OIL, GAS & SHIPPING MAGAZINE www.ogsmag.com

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KaMOS® Patented Portable Air-driven Valve Actuator

- the efficient solution for manual valves KaMOS® Patented Portable Valve Actuator increase the effiency when opening and closing manually operated heavy duty valves, head valves and gas transport valves for on- and offshore industry.

For valves taking up to 4 man-hours to open and close, KaMOS® Patented Portable Valve Actuator will perform the same work in 5 minutes with only one man to operate.

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Selected references: Statoil, ConocoPhillips, BP, Mærsk, ExxonMobil, Total, AMEC, Score

“If you are spending too much time turning manual valves - Please contact us!”

P.O.Box 484, N-4291 Kopervik, Norway • Tel +47 52 84 43 40 • Fax +47 52 84 43 41 • offshore@kamos.no • www.kamos.no

“By applying the KaMOS® Patented Portable Valve Actuator, a heavy duty valve may be opened or closed within 10 minutes, while the same operation may take up to 2 hours using manual power” - STATOIL

- time, cost & safety efficient -

Sullom voe terminal- BP PLC

Thunder Horse Water Injection, In Amenas Compression Point, Thomson Quad 204, Juniper, Persephone, Oman Khazzan and Thunder Horse South Expansion. All are scheduled for completion between now and 2017.

Kizomba Satellites phase 2 is a subsea infrastructure development of the Kakocha, Bavuca and Mondo South fields, tied back to the existing Kizomba B and Mondo floating production, storage and offloading (FPSO) vessels and is expected to recover around 190 million barrels of oil. The project scope includes subsea wells, FPSO topside modifications and installation of flowlines and subsea equipment. The development is located approximately 150 kilometres off the coast of Angola in water depths of around 1350 metres.

“In Salah Gas, a joint venture with Statoil and Sonatrach, is one of the largest dry gas joint venture projects in Algeria” 66

OIL, GAS & SHIPPING MAGAZINE www.ogsmag.com

In Salah Gas, a joint venture with Statoil and Sonatrach, is one of the largest dry gas joint venture projects in Algeria. The venture involves the development of seven proven gas fields in the southern Sahara, 1,200km south of Algiers, and has been onstream since July 2004.

Greater Plutonio Phase 3 started up in June this year and is expected to sustain production through the existing Greater Plutonio FPSO, in Block 18, by developing six wells (four producers and two water injectors), connected into the existing subsea infrastructure.

The Western Flank A project is expected to extend the production plateau of BP’s assets in the Australian North West Shelf by approximately two years. The project develops the Goodwyn H and Tidepole fields to deliver over 230 million barrels of oil equivalent with five subsea wells tied back to the existing Goodwyn A platform. The project scope also includes brownfield modifications to the topsides and the installation of a new riser.

The Thunder Horse field is located around 120 miles southeast of New Orleans in over 6,000 feet of water. Phase 1 of this water injection program is expected to develop 65 million barrels of oil equivalent (gross) of the Pink reservoir resources as well as establishing pressure support. Phase 1 scope comprises refurbishment and replacement of existing topsides and subsea

BP Group existing plant. It is expected to develop 216 million barrels of oil equivalent and to produce 107,000 barrels of oil equivalent per day at its peak.

Point Thomson is a remote natural gas field located on Alaska’s North Slope, approximately 60 miles east of Prudhoe Bay. It is estimated to hold about 25% of known natural gas on the North Slope. Processing facilities include separation, compression and utilities plants, three new wells and gathering and condensate export lines. The project is designed to produce 10,000 barrels per day of condensate at start-up. A pipeline is being installed with capacity of 70,000 barrels per day, which will take gas and condensate to the Trans-Alaska Pipeline.

The Juniper project includes the construction of a normally unmanned platform, together with corresponding subsea infrastructure. Fabrication began in 2014. The Juniper facility will produce gas from the Corallita and Lantana fields located 50 miles off the south-east coast of Trinidad, in water depth of approximately 360 feet. The development is expected to include five subsea wells and to have a production capacity of approximately 590 million standard cubic feet per day. Gas from Juniper will flow to the Mahogany B hub via a new six-mile flowline.

The Persephone gas field is located 85 miles north-west of Karratha, Western Australia, in a water depth of approximately 415 feet. The development concept is a two well subsea tieback to the existing North Rankin complex.

This first phase of the Khazzan field development plan involves drilling approximately 300 wells using several drilling rigs.

The project is expected to develop circa seven trillion standard cubic feet of gas and deliver plateau production of one billion standard cubic feet of gas per day and 25,000 barrels per day of gas condensate. The full field development involves a 15-year drilling programme, with production tied back to a new central processing facility in Block 61, via a 315-mile gathering system.

Downstream overview

equipment, procurement and installation of new equipment and the drilling and completion of two water injection wells. The South Expansion Project comprises a new subsea drill centre located two miles from the Thunder Horse platform. Three new wells and an existing fourth well are expected to tie-into the new drill centre. Topsides scope is minimal as a result of maximising use of existing subsea infrastructure.

“Point Thomson is a remote natural gas field located on Alaska’s North Slope, approximately 60 miles east of Prudhoe Bay” In Amenas is a wet-gas field, also operated in partnership with Algerian state oil company Sonatrach and Statoil. The field is approximately 810 miles from Algiers and about 40 miles west of the Libyan border. The project scope consists of two gas turbine compressor trains, a new slug-catcher, a produced water surge drum, associated utilities and control systems and tie-ins to the

In 2014 BP saw continued improvement in its process safety and delivered strong operational performance resulting in profit and operating cash flow growth. The downstream segment has significant operations in Europe, North America and Asia, and also manufactures and markets products in Australasia, Africa and Central and South America. It is made up of three businesses.

• Fuels includes refineries, fuels marketing and

convenience retail businesses, together with global oil

supply and trading activities that make up fuels

value chains (FVCs). It sells refined petroleum products

including gasoline, diesel and aviation fuel.

• Lubricants manufactures and markets lubricants and

related products and services globally, adding

value through brand, technology and relationships, such

as collaboration with original equipment manufacturing partners.

• Petrochemicals manufactures products at locations

around the world, mainly using proprietary

BP technology. These products are then used to

make essential consumer products, such as paint, plastic

bottles and textiles.

BP’s high-quality and material project portfolio is set to underpin growth to 2020 and beyond. More than 900 mboed of new net production is expected by 2020 and 2015 - 2020 project margins are set to be over 35% greater than the 2014 segment average.

OIL, GAS & SHIPPING MAGAZINE www.ogsmag.com

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STAINLESS STEEL, DUPLEX, SUPERDUPLEX, 6MO & NICKEL ALLOYS STAINLESS STEEL, DUPLEX, SUPERDUPLEX, 6MO & NICKEL ALLOYS

Hot formed butt weld fittings up to 56”

FULL RANGE BUTT WELD FULL RANGEOF OF BUTT WELDFITTINGS FITTINGS FROM WITH FROM PRODUCTION WITH NORSOK M-650 Ed. 44 approval NORSOK M-650 Ed. approval

Cold formed butt weld fittings from ½” to 16”

STAINLESS STEEL, DUPLEX, SUPERDUPLEX, 6MO & NICKEL ALLOYS

In 1988, Raccortubi S.p.A. established Tecninox S.r.l., manufacturer of butt weld fittings in stainless steel, duplex, superduplex, 6Mo and nickel alloys, with the intention of becoming a manufacturer as well as a stockist and supplier.

It recognised that, by incorporating the Tecninox production, it could be of added value to its customers thanks to a new-found ability to supply the critical fittings element of a package quickly, on demand and to customer specifications.

Over the course of the years, Raccortubi and Tecninox have worked together for the continuous improvement of productive processes via automation, use of advanced technology and evolution of quality assurance, meaning that today the achievement of added value for the client is stronger than ever before. Raccortubi Group can offer customers fittings to NORSOK M-650 Ed. 4 specifications, manufactured by its integrated production plants, from strategically placed distribution points around the world. Raccortubi’s subsidiaries in Dubai, Brazil and Singapore are conveniently located near shipbuilding ports to supply pipes, tubes, fittings and flanges in stainless steel and special alloys directly from stock.

Raccortubi Group is making sure that it has fully-tested and certified piping materials in full compliance with the vast majority of end-user requirements at its disposal, from both production and stock, to fulfil customer needs to short timescales.

PETROL RACCORD EXTENDS QUALITY HOMOLOGATIONS WITH NORSOK M-650 Ed. 4 approval Under Raccortubi ownership, Petrol Raccord has renewed its commitment to the most up-to-date quality standards, adding NORSOK M-650 Ed. 4 certificates to its already-substantial collection.

Using the hot forming method, Petrol Raccord manufactures butt weld fittings up to 56”, almost without wall thickness limitations, for the oil & gas, power generation and petrochemical industries. It has its own internal laboratory and, thanks to its experience and expertise, holds an impressive number of end-user approvals, as well as ASME certification for the nuclear industry.

Both Raccortubi Group’s integrated manufacturing plants, Petrol Raccord and Tecninox, are implementing NORSOK M-650 Ed. 4 standards, which have been cemented in place as part of their day-to-day procedures. Not only are such norms practised without fail, but the resulting top-notch processes and quality controls are constantly under analysis for improvement and further development.

By ensuring manufacturing to such specifications at its production facilities, Raccortubi Group is guaranteeing the supply of the highest-quality fittings in stainless steel, duplex, superduplex, 6Mo and nickel alloys in the provision of complete project packages.

raccortubigroup.com