Malaysia Stands. Analysing the Flow

Transcription

1 PETROMIN Marine & Offshore 2018 mar apr Malaysia Stands Firm Despite the low price of global crude oil, the oil & gas sector remains important to the country as it contributes between 20 to 30 percent to the country s Gross Domestic Product (GDP). Low-Speed Low-Pressure X-DF Technology When the development of the two-stroke low-pressure DF lean-burn technology started, the extensive experience from Wärtsilä s four-stroke developments could be utilized as a base in several technology areas. These include engine automation and control, pilot injection, gas supply system and engine testing to mention a few. mar -apr 2018 VOL. 1 NO.02 Analysing the Flow Jason Yew, Sales Director KROHNE-EMAS Oil & Gas Sdn Bhd, spoke to Petromin Marine & Offshore about the measurement technologies one of the industry leaders have to offer. Key are ultrasonic and Coriolis meters.

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3 Petromin Marine & Offshore is published by Mediabuz PTE LTD 21 8 Boon Lay Way, #09-10 Singapore Tel: (65) Fax: (65) Website: contents Reports 06 EIA Short-Term Energy Outlook (STEO) The following is the March 2018 instalment of the monthly forecast provided by the U.S. Energy Information Administration. 12 Oil Remains Critical Despite the low price of global crude oil, the oil & gas sector remains important to the country as it contributes between 20 to 30 percent to the country s Gross Domestic Product (GDP). 20 Natural Gas Offers Promise Malaysia was the world s third-largest exporter of liquefied natural gas (LNG) after Qatar and Australia in The country s growing domestic demand and regional gas imbalances in the past few years prompted the country to open its first regasification terminal as another supply source. 28 Bids & Pieces Petromin Marine & Offshore is a business publication covering technologies, trends and news related to the oil & gas and marine industries in the Asia Pacific region. The Publisher reserves the right to accept or reject all editorial or advertising material, and assumes no responsibility for the return of unsolicited artwork or manuscripts. All rights reserved. Reproduction of the magazine, in whole or in part, is prohibited without the prior written consent, not unreasonably withheld, of the publisher. Reprints of articles appearing in previous issues of the magazine can be had on request, subject to a minimum quantity. The views expressed in this journal are not necessarily those of the publisher and while every attempt will be made to ensure the accuracy and authenticity of information appearing in the magazine, the publisher accepts no liability for damages caused by misinterpretation of information, expressed or implied, within the pages of the magazine. All correspondence regarding editorial, editorial contributions or editorial content should be directed to the Editor. The magazine is available at an annual subscription rate of S$220. Please refer to the subscription form or contact the subscription department for further details at Fax: (65) March to April

4 Petromin Marine & Offshore is a magazine dedicated to the technology of the oil & gas and marine industries in all its forms. Within the pages of the magazine you will find information, based on technical articles from the experts in their respective fields, as well as reports on various topics relating to the industry as a whole. Also within the pages of Petromin Marine & Offshore you will find interviews, case studies and field reports written by our staff or technical correspondents. We also cater to the IT, instrumentation and control of the energy and marine industries. Covering both energy and marine activities and starting from the technology of seismic surveying, through interpretation and application, we will present articles on all aspects of drilling, reservoir treatment, well treatment, testing, completion, through to production, storage and transportation. Pipelines figure highly in the technology covered as does FPSOs, drilling rigs, production platforms and gas handling equipment. 36 Scene & Heard Technology 42 Analysing the Flow Jason Yew, Sales Director KROHNE-EMAS Oil & Gas Sdn Bhd, spoke to Petromin Marine & Offshore about the measurement technologies one of the industry leaders have to offer. Key are ultrasonic and Coriolis meters. 44 Low-Speed Low-Pressure X-DF Technology When the development of the two-stroke low-pressure DF lean-burn technology started, the extensive experience from Wärtsilä s four-stroke developments could be utilized as a base in several technology areas. These include engine automation and control, pilot injection, gas supply system and engine testing to mention a few. While we are indebted to our regular contributors, we are at all times on the lookout for new material and if you or your company have a technology you would like to share, or a paper you feel deserves publication, please do contact us at editor@media-buz.com with your suggestions. If there are aspects of the upstream industry you feel are missing from our coverage, please do us and tell us. We will do our best to supply coverage of that aspect in the future. Regular Focus 04 Editorial 28 Bids & Pieces 36 Scene & Heard 59 Calendar of Events MCI (P) 101/02/2018 ISSN Published by Mediabuz Pte Ltd. Printed by KHL Printing Co Pte Ltd 2 March to April 2018

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6 Editorial Chief Editor Mohana Velu Rajendran Group Editor Vishnu Pillai Tel: Graphic Artist Chua Ai Hwa Advertising Co-ordinator Jaquilyn Tel: Onwards and Upwards Subscription/Circulation Mary Dela Pena Tel: Conference Co-ordinator Mary Dela Pena Tel: EDITORIAL ADVISORY BOARD Dr. Michael J. Economides Professor of Chemical Engineering University of Houston Prof. F.E. Banks Uppsala University Sweden Prof. Eugene M. Khartukov International Center for Petroleum Business Studies Moscow, Russia Stuart Crampin University of Edinburgh Lau Siew Ming JP Kenny Wood Group Saeid Mokhatab Process Technology Manager Tehran Raymand Consulting Engineers Correspondents Australia/PNG Brian Wickins Dhaka, Bangladesh Ghazi Mahmud Iqbal Beijing, China Wang Yong Delhi, India Siddharth Raghavan New Zealand Neil Ritchie Pakistan Dr Salman Salf Ghouri It might eventually be premature (I doubt it though), it might sound immature, it might seem to be over optimistic, but I cannot help being excited about oil reaching the $70 mark. Yes, I m fully aware that $70 is nothing to crow about when you consider that we were around the $100 marker for a considerable length of time. I m also aware that the price has risen based on a number of political factors and the doubts hovering over some producers such as Venezuela. However, after the last couple of years of what I deem to be torturous times, I think I am, just like the entire oil and gas industry, entitled to a little positivity. Now, there is a distinct difference between being cautious and being pessi- mistic; the two should not be confused. Certainly, there is understandable caution after what the industry has been through the last few years, but I simply cannot condone the pessimists and doomsday prophets out there who insist that hitting this new recent high is of no significance whatsoever. What makes these people insufferable is the fact that not only do they suffer from economic myopia, they refuse to evaluate matters logically and proportionately. Here are some opinions which I have consistently been presented. Chief is that we will never return to the $100 barrel, we can hope for $80 at best. The $80 benchmark is the latest number being bandied around. The same persons were insistent to the 4 January March to to April February

7 point of guaranteeing it 12 months ago that $60 was all that could be hoped for, but as prices rise so does their cutoff. It s easy to be right when your prediction is so malleable. Furthermore, as much as the industry enjoyed the $100 barrel, the industry and future plans were not engineered on the platform of a $100 barrel. Sure, being caught up in the euphoria of the heady prices some over enthusiastic plans were discussed and carried out, but the industry can certainly be content with a $80 barrel. My personal favourite is that whilst gains come in small increments when a fall takes place it is sudden and drastic. In my opinion these self-professed analysts have very little knowledge of world economics or trading. This phenomenon is applicable to all industries, not just the oil and gas. In every industry, when there is a crash it is drastic, and it is sudden. Think of the property crashes and financial institution collapses. Think of coffee bean trading collapses. Hospitality. Shipping. The list goes on. Of course, some industries are more volatile than others but that s simply because when times are good they enjoy much bigger margins. These folks (the naysayers) are stating the obvious and are talking without actually saying anything. ADVERTISING SALES OFFICES HEAD OFFICE SINGAPORE Mediabuz PTE LTD 8@TradeHub 21 8 Boon Lay Way #09-10 Singapore Tel: Fax: Contact person: Mary Dela Pena info@media-buz.com MEDIA REPRESENTATIVES AUSTRALIA: Brian Wickins Tel: Fax: A close second is the argument that the increases are only temporary and that prices will start getting depressed again. I totally agree. However, that can be said of falling prices too. Prices in general are temporary. Perhaps what they mean is that they expect gains to last shorter than losses and that there will be no continual growth of gains. That, to me, is like saying water is wet. Economics 101. That does not mean that all gains should be met with skepticism. I don t think we should put the champagne on ice just yet; we certainly aren t out of the woods by any means. That does not mean we cannot take the opportunities to be happy about the small victories the industry achieves. The time to hope has passed, it is now time to believe. Group Editor Vishnu Pillai ITALY: Anna De Bortoli Tel: milano@ediconsult.com JAPAN: Ken Takahashi Tel: Fax: SOUTH KOREA: Chang Hwa Park Tel: (+82) (+2) /3 Fax: (+82) (+2) VIETNAM: Nguyen Thanh Trung Tel: Fax: trung.pcn@gmail.com March to April

8 Industry Outlook EIA Short-Term Energy Outlook (STEO) The following is the March 2018 instalment of the monthly forecast provided by the U.S. Energy Information Administration. North Sea Brent crude oil spot prices averaged $65 per barrel (b) in February, a decrease of $4/b from the January level and the first month-over-month average decrease since June EIA forecasts Brent spot prices will average about $62/b in both 2018 and 2019 compared with an average of $54/b in EIA expects West Texas Intermediate (WTI) crude oil prices to average $4/b lower than Brent prices in both 2018 and NYMEX WTI contract values for May 2018 delivery traded during the five-day period ending March 1, 2018, suggest a range of $51/b to $76/b encompasses the market expectation for June 2018 WTI prices at the 95% confidence level. EIA estimates that U.S. crude oil production averaged 10.3 million barrels per day (b/d) in February, up 230,000b/d from the January level, when there were some well freeze-offs in the Permian and Bakken. EIA has reported that total U.S. crude oil production averaged 9.3 million b/d in 2017, ending the year with production of 9.9 million b/d in December. EIA projects that U.S. crude oil production will average 10.7million b/d in 2018, which would mark the highest annual average U.S. crude oil production level, surpassing the previous record of 9.6 million b/d set in EIA forecasts that 2019 crude oil production will average 11.3million b/d. 6 March to April 2018

9 EIA estimates that inventories of global petroleum and other liquid fuels declined by 0.6million b/d in In this forecast, global inventories grow by about 0.4million b/d in 2018 and by another 0.3million b/d in EIA estimates that U.S. dry natural gas production averaged 73.6 billion cubic feet per day (Bcf/d) in EIA forecasts that natural gas production will average 81.7Bcf/d in 2018, establishing a new record. That level would be 8.1Bcf/d higher than the 2017 level and the highest annual average growth on record. EIA expects natural gas production will also increase in 2019, with forecast growth of 1.0Bcf/d. Crude Oil The front-month futures price for North Sea Brent crude oil In February, the U.S. benchmark Henry Hub natural gas spot price averaged $2.66 per million British thermal units (MMBtu), down $1.03/MMBtu from January. Winter weather moderated in February after extremely cold temperatures in much of the country during the first half of January. U.S. heating degree days were an estimated 17% lower than the 10-year average for February, which contributed to lower settled at $63.83 per barrel (b) on March 1, a decrease of $5.82/b since February 1. Front-month futures prices for West Texas Intermediate (WTI) crude oil for delivery at Cushing, Oklahoma, decreased $4.81/b over the same period, settling at $60.99/b on March 1 (Figure 1). February Brent and WTI monthly average spot prices were $3.76/b and $1.49/b lower than the January average spot prices, respectively. consumption and prices. Crude oil prices declined in February after seven consecutive EIA expects natural gas prices to moderate in the coming months, based on a forecast of record natural gas production levels. EIA expects Henry Hub spot prices to average months of increases. Despite the recent price declines, most fundamental crude oil supply and demand indicators suggest global petroleum inventories are declining. $2.72/MMBtu in March and $2.99/MMBtu for all of In 2019, EIA forecasts prices will average $3.07/MMBtu. NYMEX contract values for June 2018 delivery that traded during the five-day period ending March 1, 2018, suggest that a range of $2.16/MMBtu to $3.49/MMBtu encompasses the market expectation for June Henry Hub natural gas prices at the 95% confidence level. EIA estimates that total commercial petroleum inventories in countries in the Organization for Economic Cooperation and Development (OECD) declined to 2.83 billion barrels in February 2018, a decrease of 211 million barrels since February 2017 and the largest annual decrease in inventories since Inventories are 40 million barrels (1.4%) higher than the five-year average level for February, the narrowest difference to five-year March to April

10 average levels since November 2014, suggesting an increasingly balanced market. A significant increase in volatility may have prompted the inverse VIX ETF to close positions. Several inverse VIX products have ceased trading, having lost more than 80% of their value A significant increase in price volatility after prices started declining in equity and bond markets likely affected crude oil prices as well. The rolling 60-day correlation between daily price changes of WTI crude oil and the S&P 500 index recently increased from in one day on the some of the highest trading volume in the many ETFs history. Both the VIX and the OVX have declined since their early February increases, but remain at higher levels than at the beginning of near zero at the beginning of January to over 0.3 in late February. The VIX, a measure of implied volatility (the market s expected range of near-term price changes) on S&P 500 index options, closed above the OVX, a measure of implied volatility on crude oil options prices, for four consecutive days in early February. Not only was this the first time since 2008 that the VIX closed above the OVX, but the VIX has only closed above the OVX four other times since the inception of the OVX in 2007 (Figure 2). The Brent-WTI price spread narrowed to its lowest level in more than six months, closing at $3.03/b on March 1 (Figure 3). Several factors specific to the crude oil market in the U.S. midcontinent could be contributing to a narrowing spread. Crude oil stocks in Cushing, Oklahoma, the delivery point for the U.S. light sweet crude oil futures contract, continued to decrease in February. Stocks declined to less than 29 million barrels the week ending February 23, 2018, the lowest level in more than three years, and they are being drawn down at the largest rolling 13-week rate since EIA began publishing Cushing stock levels in Recent trade press reports that the Keystone pipeline, which flows directly into Cushing, is still operating below nameplate capacity. Crude oil inputs to refineries in Petroleum Administration for Defense District (PADD) 2 averaged 3.7 million b/d for the four weeks ending February 23, 2018, according to EIA s Weekly Petroleum Supply Report, which would be an all-time high for the month of February. Under typical trading conditions, a single commodity would be expected to have higher volatility than an index whose underlying value consists of a basket of 500 large capitalization stocks, representing a variety of U.S. companies. Although the direct causes of increased equity market volatility remain uncertain, increased trading volume of inverse VIX exchangetraded funds (ETF) and exchange-traded notes, as well as direct selling of VIX futures contracts, could have contributed to the increase. 8 March to April 2018

11 Gasoline inventories, which typically decline between January and February, rose this year in all regions of the United States. Total U.S. gasoline stocks rose 6.3 million barrels between the weeks ending February 2 and February 23. Total U.S. gasoline stocks have declined between January and February on average by 5.8 million barrels over the past five years, according to EIA s Petroleum Supply Monthly (PSM). In addition to high refinery demand in PADD 2, higher export demand could be contributing to near-term price support for U.S. light sweet crude oil. Weekly U.S. crude oil exports were more than 2 million b/d for the week ending February 16, 2018, the second highest level since EIA began publishing weekly export data from U.S. Customs and Border Protection in 2016 (Figure 4). The Louisiana Offshore Oil Port (LOOP) is the largest crude oil import terminal in the United States, but recently the port began to test loading crude oil for export. LOOP loaded a Very Large Crude Carrier(VLCC) on February 18, which can hold approximately 2 million barrels of crude oil. Further infrastructure developments along the U.S. Gulf Coast (PADD 3) could allow more U.S. crude oil exports. The ultra-low sulfur diesel (ULSD) front-month futures price decreased 20 cents/gal from February 1 to settle at $1.89/ gal on March 1. The ULSD-Brent crack spread (the difference between the price of ULSD and the price of Brent crude oil) decreased by 7 cents/gal over the same period, settling at 37 cents/gal (Figure 6). The front-month futures price of reformulated blendstock for oxygenate blending (RBOB, the petroleum component of gasoline used in many parts of the country) settled at $1.90 per gallon (gal) on March 1 (Figure 5), virtually unchanged since February 1. The RBOB-Brent crack spread (the difference between the price of RBOB and the price of Brent crude oil) increased by 14 cents/gal over the same period to settle at 38 cents/gal. The RBOB-Brent crack spread declined 5 cents/gal in February before the contract changed to summer grade gasoline on March 1, causing a significant one day increase in the crack spread. EIA forecasts U.S. hydrocarbon gas liquids consumption to average 2.94 million barrels per day (b/d) in 2018 and 3.19 million b/d in 2019, which are about 50,000 b/d and 60,000 b/d higher, respectively, than forecast in the February STEO. The March forecast incorporates higher-than-expected monthly ethane consumption data for November and December, which provide a higher starting point for expected growth from new ethane-consuming petrochemical plants. March to April

12 Similar to the movements seen in the gasoline market, distillate crack spreads fell in February, as distillate inventories rose counter-seasonally. In the Central Atlantic (PADD 1B), which includes the New York Harbor delivery point of the ULSD futures contract, distillate inventories rose 0.7 million barrels between the weeks ending February 2 and February 23. In comparison, distillate inventories in PADD 1B declined 2.7 million barrels on average between January and February in the past five years, according to the PSM. For much of February, the U.S. East Coast and the U.S. Northeast experienced warmer-than -normal temperatures, which likely reduced demand for home heating. EIA expects U.S. liquid fuels consumption to grow 0.47 million b/d (2.4%) in 2018, the highest growth rate since EIA projects that most of the consumption growth will come from natural gas-sourced products. HGL consumption is expected to account for 0.34 million b/d of total liquid fuels consumption growth. Ethane is expected to account for almost 65% of this HGL consumption growth, as new domestic ethylene crackers begin operating. Natural Gas The front-month natural gas futures contract for delivery at In recent months, year-over-year growth in total U.S. liquid fuels consumption and exports has accelerated to levels not seen since Since October 2017, year-over-year growth in total liquid fuels consumption and exports averaged 1.0 million b/d, with an increasing portion of the growth coming from hydrocarbon gas liquids (HGL), which includes propane and ethane (Figure 7). Henry Hub settled at $2.70/million British thermal units (MMBtu) on March 1, a decrease of 16 cents/mmbtu from February 1 (Figure 8). Warmer weather in the second half of January and in February contributed to the fall in natural gas prices. U.S. population-weighted heating degree days (HDD) averaged 12% below normal for the four weeks ending February 22, which put downward pressure on natural gas prices throughout the month. The Henry Hub natural gas spot price averaged $2.66/MMBtu in February, $1.03/MMBtu lower than January. 10 March to April 2018

13 The historical and implied volatilities of natural gas prices both increased in January, as typically happens each winter (Figure 9). Historical volatility reached 67% on February 5, the highest level since January 2017, reflecting the price spikes at the beginning of January and significant price declines at the end of the month. Implied volatility, however, declined quickly at the end of January and fell to 26% on February 28, the lowest implied volatility since June Implied volatility represents the market s expectation about near-term price movements; as a result, the low natural gas price implied volatility may indicate that strong production growth will be sufficient to meet demand, despite inventories that are currently below their five-year average. contract expiring above $3/MMBtu; the probabilities fell from 42% at the beginning of the month to 28% on March 1 (Figure 10). Natural gas inventory withdrawals for the four weeks ending February 23 were 53 billion cubic feet (9%) below the fiveyear average, which likely contributed to an improved supply Natural gas futures prices fell in the front-month contract, and outlook for the next several months. substantial price decreases occurred in contracts several months into the future. These price declines significantly reduced the market-derived probability of the July 2018 Henry Hub futures This periodical thanks the U.S. Energy Information Administration (EIA) for providing this article for publication. March to April

14 Country report Oil Remains Critical Despite the low price of global crude oil, the oil & gas sector remains important to the country as it contributes between 20 to 30 percent to the country s Gross Domestic Product (GDP). With over 3,500 oil and gas (O&G) companies in Malaysia, comprising both international and local companies, the multiplier effect generated by this sector is still sizable and is recognized by PET- RONAS and the Government of Malaysia as a strategic and priority sector. Malaysia s energy industry is a critical sector of growth for the entire economy and has accounted for nearly 20% of the country s total gross domestic product in recent years. New tax and investment incentives, which started in 2010, promote oil and natural gas exploration and development in the country s deepwater and marginal fields, energy efficiency measures, and use of alternative energy sources. These fiscal incentives are part of the country s economic transformation program to leverage its resources and geographic location to become one of Asia s top energy players by Another key pillar in Malaysia s energy strategy is to become a regional oil and natural gas storage, trading, and development hub that will attract technical expertise and downstream services that can compete within Asia. Malaysia, located within Southeast Asia, has two distinct parts. The western half contains the Peninsular Malaysia, and the eastern half includes the states of Sarawak and Sabah, which share the island of Borneo with Indonesia and Brunei. The country s western 12 March to April 2018

15 coast runs along the Strait of Malacca, an important route for the seaborne trade that links the Indian and Pacific Oceans. Malaysia s position in the South China Sea makes it a party to various disputes among neighbouring countries over competing claims to the sea s oil and natural gas resources. Although it has bilaterally resolved competing claims with although in the past decade, more exploration and discovery of reserves have taken place in deepwater areas in eastern Malaysia. Malaysia s prize benchmark crude oil fields include Tapis, (located offshore Peninsular Malaysia) and Miri, Kikeh, and Kimanis (located near Borneo Island in the eastern region). Vietnam, Brunei, and Thailand, an area of the Celebes basin remains in dispute with Indonesia. Potential territorial disputes with China, Vietnam, and the Philippines could emerge as the country s exploration initiatives move into the deepwater areas of the South China Sea. Starting in 2015, Malaysia witnessed marginal growth in oil production and reserves, while gas production continues to decline. This continuing decline in production at Malaysia s major shallow water producing oil fields has prompted government efforts to encourage investment in Enhanced Oil Recovery (EOR) and development of marginal and deepwater fields through risk-sharing agreements. Malaysia s new reserves are found mostly off the coast of Northern Borneo between 200 to 1200 meters deep, making it more costly to extract these resources. Sector Organization Energy policy in Malaysia is set and overseen by the Economic Planning Unit (EPU) and the Implementation and Coordination Unit (ICU), which both report directly to the Office of the Prime Minister. Malaysia s national oil and gas company, Petroliam Nasional Berhad (PETRONAS), holds exclusive ownership rights to all oil and natural gas According to sources, Malaysia held proved oil reserves of 3.6 billion barrels as of January 2017, the fourth-highest reserves in Asia-Pacific after China, India, and Vietnam. Nearly all of Malaysia s oil comes from offshore fields. The continental shelf is divided into three producing basins: the Malay basin, offshore peninsular Malaysia in the western area, and the Sarawak and Sabah basins in the eastern region. About 40% of the country s oil reserves are located in the Malay basin and tend to be light and medium sweet crude oil grades from shallow waters, exploration and production projects in Malaysia, and it is responsible for managing all licensing procedures. Malaysia s Prime Minister directs PETRONAS and controls appointments to the company s board. PETRONAS holds stakes in most of the oil and gas blocks in Malaysia, and it is one of the largest contributors to Malaysian government revenues, accounting for more than 20% of the country s taxes and dividends in Since its incorporation in 1974, PETRONAS has grown to be a world-renowned, integrated international oil and gas company with upstream March to April

16 and downstream interests in more than 70 countries. PETRONAS holds equity in all upstream production-sharing contracts (PSC). ExxonMobil, Shell, and Murphy Oil are currently the foreign oil companies producing the most oil in Malaysia. New opportunities for investment in Malaysia s energy sector have attracted other foreign oil independents such as Repsol (Spain), Lundin Petroleum (Sweden), Roc Oil Company (Australia), and Petrofac (UK). In 2015, Indonesia s national oil company (NOC), Pertamina, purchased 30% of Murphy Oil s assets in Malaysia as Indonesia seeks to book upstream hydrocarbon production from overseas assets. Sarawak Chief Minister Abang Johari Openg State Rule Sarawak announced in March that it now has complete mining rights over its territory, making it the first state in Malaysia to form a stateowned oil and gas company. Sarawak Chief Minister Abang Johari Openg said the formation of Petros, which was founded last year, was part of the promise made by the federal government to return eroded rights from the Malaysia Agreement 1963 (MA63), signed when the giant state agreed to become part of Malaysia. This gives Sarawak full regulatory authority of the upstream, downstream aspects of the oil and gas industry, said Datuk Abang Johari at an event to launch Petros in the Sarawak capital of Kuching. The announcement comes after Malaysian Prime Minister Najib Razak gave assurances that Sarawak s longstanding demands will be met. Under the current arrangement, Malaysia s national oil and gas company PETRONAS has legal ownership and rights over oil fields nationwide. In return, PETRONAS makes cash payments to the federal and state governments, such as Sarawak, where petroleum deposits are dug up or processed. The formation of Petros would allow Sarawak to earn its own revenues directly through exploration and in downstream activities, rather than solely relying on the cash payments. But the announcement does not affect PETRONAS ongoing works in Sarawak involving 60 oil and gas producing fields. 14 March to April 2018

17 natural gas liquids, biofuels, and refinery processing gains) in 2016 was an estimated 744,000 barrels per day (b/d), a 15% increase from a recent low in 2013, but down from the country s peak production of 842,000 b/d in More than a quarter of Malaysian crude oil production currently originates from the Tapis field in the offshore Malay basin. The country s oil production had experienced over- Malaysia s oil and natural gas policy historically has focused on maintaining the reserve base to ensure long-term supply security while providing affordable fuel to its population through subsidized fuel sales. Prior to 2015, high international oil prices and Malaysia s increasing crude oil import levels put pressure on government expenditures for subsidies. In response, the government began introducing subsidy reforms as part of Malaysia s goal to lower the government s budget deficit and lift some of the financial burden on PETRONAS to allow the company to invest in more in upstream activities. In July 2010, the government initiated the first subsidy reductions for gasoline, diesel, and liquefied petroleum gas (LPG) with the aim of phasing out fuel subsidies by Public sensitivities over higher fuel costs stalled the reforms until September 2013, when the government increased the price of gasoline and diesel by 10.5% and 11.1%, respectively. In November 2014, Malaysia officially ended subsidies for gasoline and diesel. E&P Malaysia is Southeast Asia s secondlargest oil producer behind Indonesia. Petroleum and other liquids production (including crude oil, lease condensates, March to April

18 all decline as a result of maturing fields, particularly larger fields in the shallow waters offshore Peninsular Malaysia. Since 2014, production commenced from Lundin Petroleum s contracts: PETRONAS is the project owner and investors are the service providers receiving revenues for oil produced throughout the entire life of the project. new Bertam oilfield in the Penyu Basin from and the large deepwater Gumusut-Kakap field. This production offset some production declines from mature fields and reversed some of the declines over the past decade. The combination of new fields coming online and increased investment in enhanced oil recovery (EOR) in mature fields has also kept oil production relatively steady. International Oil Companies (IOCs) are also making new oil and natural gas discoveries in deepwater offshore areas of Sarawak and Sabah basins. These deepwater offshore fields pose more technical challenges and require greater investment by Malaysian and foreign energy firms. In 2013, PET- RONAS announced higher spending for exploration and production activities in Malaysia s oil and natural gas sector to boost oil and natural gas production and to offset the current declines from aging fields. However, following the oil price slump since 2014, the NOC announced cuts to capital expenditures by $11.2 billion between 2016 and The lower oil price environment has slowed investment in development of Malaysia s upstream oil assets and has resulted in international oil companies abandoning a few contracts. Not Yet Out of the Woods StarBiz had reported in December that PETRONAS spending requirements for upstream assets such as rigs would be halved from three years ago. The report noted that the need for jack-up rigs, which are used in exploration activities, has been reduced by half to about 10 rigs for the period , compared to the period. Malaysia s domestic oil consumption has risen while production has fallen in most years since 2003, leaving smaller volumes of oil available for exports. PETRONAS is working to attract new investments and to reverse production declines by enhancing output from existing fields through advanced EOR techniques and developing small, marginal fields through riskservice contracts (RSCs). Companies share the risk in these For local players, AmInvestment Bank Research said in a sector report recently that scope of works for these O&G service players is mainly determined on a call-up basis. 16 March to April 2018

19 The research house expects PETRONAS to maintain its cautious tone on upstream exploration and development expenditures, noting that the worst might not really be over yet. The Malaysian OGSE (Oil & Gas Services and Equipment) industry as a whole is undergoing a significant transformation, with OGSE companies working to reshape their business models and implement strategies to weather the storm. Their strategies to become more resilient and competitive tie closely to the Malaysia Petroleum Resources Corporation s (MPRC) continuous efforts in developing the capabilities of the OGSE industry. In time to come, MPRC will intensify local OGSE development for global competitiveness whilst capitalising on global energy s shift to Asia to enhance Malaysia s position as OGSE gateway of the region. system. The Kakap field came online in 2012 with production of 25,000 b/d. New production from the Gumusut field, which commenced in late 2014, has been the key driver in crude oil production growth in Malaysia following more than a decade of overall declines. Currently, output from both fields has averaged 100,000 b/d to 120,000 b/d and could peak around 135,000 b/d. Project shareholders are Shell (33%), ConocoPhillips (33%), PETRONAS (20%), and Murphy Oil (14%). The system is connected via pipelines to the new Sabah Oil and Gas Terminal located onshore at Kimanis, Malaysia. Several major projects are under development in the deepwater area offshore the Sabah state that could bolster Malaysia s oil production over the next decade. The Kikeh oil field, operated by Murphy Oil in partnership with PETRONAS, was Malaysia s first deepwater oil-producing field. The Kikeh field came online in 2007 with peak production potential at 120,000 b/d. However, estimated production in 2015 was only 15,000 b/d. The Siakap North-Petai field is a satellite field commissioned in 2014 to tie back to the Kakap field. It has a peak production rate of 35,000 b/d, which will offset some production declines from Kakap. The Malikai oil and gas field is another deepwater find located offshore northwestern Sabah and has a peak production capacity of 60,000 b/d. Shell, the operator and a 35% stakeholder, brought Malikai online at the end of Other project partners include ConocoPhillips (35%) and PETRONAS (30%). The Malikai project uses a tension-leg platform and other advanced offshore drilling technologies. Trade Another deepwater area offshore Sabah, the Gumusut-Kakap project, uses the region s first deepwater floating production Malaysia remained a net oil exporter of crude oil and petroleum products in 2016 despite the narrow gap between production and consumption in the past several years. March to April

20 References EIA Energy Commission of Malaysia, Malaysia Energy Information Hub export.gov HIS Energy IEA International Monetary Fund Malaysia Energy Commission MPRC processoilgas Murphy Oil Corp Oil & Gas Journal PETRONAS Prime Minister Department of Malaysia, Performance Management and Delivery Unit Rigzone SapuraKencana Shell The Oil & Gas Year The Star The Straits Times Malaysia exports about half of its crude oil production because the crude quality (light and sweet) is attractive to the Asian markets and fetches a higher premium compared with other crude oil blends. Malaysia imports lower-cost heavy sour crude oil, about half from the Middle East and the rest from several other regions, for its refineries and domestic needs. In 2016, Malaysia imported nearly 200,000 b/d of crude oil for processing at its oil refineries. Malaysia exported an eight-year high of 333,000 b/d of crude oil in Almost all of Malaysia s crude oil exports are shipped within Asia Pacific, the bulk of which were sent to Australia, India, Thailand, Singapore, and Indonesia. Japan purchased more crude oil from Malaysia to use for power generation following the loss of nuclear electric generation after the country s Fukushima accident in 2011, although these export volumes have now returned to pre- Fukushima levels. The country s imports of petroleum products have grown faster than its exports in the past few years because of weaker oil demand in other parts of Asia. Much of Malaysia s oil product trade occurs within Asia, especially with neighboring Singapore. Gasoline is the key import product, making up about 46% of petroleum product imports and about 20% of all oil product demand. Malaysia exports about half of its diesel production. Malaysia s oil demand slowed in 2015 and 2016 as a result of weaker economic growth and competition with other fuels such as natural gas and coal. 18 March to April 2018

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22 Country report Natural Gas Offers Promise Malaysia was the world s third-largest exporter of liquefied natural gas (LNG) after Qatar and Australia in The country s growing domestic demand and regional gas imbalances in the past few years prompted the country to open its first regasification terminal as another supply source. According to sources, Malaysia held 42 trillion cubic feet (Tcf) of proved natural gas reserves as of January 2017, and it was the fifth-largest natural gas reserve holder in the Asia-Pacific. More than half of the country s natural gas reserves are located in its eastern areas, predominantly offshore Sarawak. Sarawak and Sabah have an increasing amount of non-associated gas reserves that have offset some of the declines from mature oil and natural gas basins offshore Peninsular Malaysia. Similar to the oil sector, Malaysia s state-owned PETRONAS dominates the natural gas sector. The company has a monopoly on all upstream natural gas developments, and it also plays a leading role in downstream activities and the liquefied natural gas trade. Most natural gas production comes from PSAs operated by foreign companies in conjunction with PETRONAS. Shell remains the largest gas producer and a key player in the development of deepwater fields in Malaysia. Other international companies that have sizeable upstream investments in Malaysia s natural gas fields include Murphy Oil, ConocoPhillips, Nippon Oil, INPEX, and Mitsubishi. Gas Malaysia is the largest non-power natural gas distribution company in Malaysia and the only one that can operate on Peninsular Malaysia. Sarawak Gas Distribution Company, which is 70%-owned by the government, serves Sarawak gas consumers, 20 March to April 2018

23 all consumers. By early 2017, the price had risen by 44% for electric power customers and by 68% for industrial and commercial customers over the previous three years. Between 2014 and the end of 2016, the concurrent fall in Malaysian LNG prices by about half to less than $6 per million British thermal units has significantly narrowed the gap between domestic and international gas prices. The government intends to further and Sabah Energy Corporation distributes natural gas in the Sabah state. ratchet up the natural gas tariff for non-power consumers every six months until 2019, which is expected to result in a 23% increase from the January 2017 level. The Malaysian government has regulated natural gas prices for end users. Historically, it has capped the domestic rates at levels considerably below imported LNG and prices paid by neighbouring Singapore. The Malaysian government has provided subsidies to PETRONAS and power producers. Overall, the artificially low natural gas prices in Malaysia have increased the government deficit, inhibited some upstream investment by PETRONAS, and increased domestic demand. In efforts to reduce natural gas subsidies and raise investment, the government implemented a price reform in The policy seeks to raise the natural gas price for electric power users every six months to bring domestic natural gas prices closer to prices in the international market. Exploration and Production Malaysia s dry natural gas production has risen steadily over the past two decades, reaching 2.2 Tcf in The Malaysian government estimates 2016 production rose to nearly 2.4 Tcf in 2016 as a result of projects that have come online in the past two years. Meanwhile, domestic natural gas consumption, which accounts for roughly 50% of production, has also increased over the past decade, but at a slower pace. In 2014, the power sector accounted for 62% of natural gas consumption, and the industrial sector accounted for 37%, according to Malaysian statistics. The remaining use was from residential, commercial, and transportation sectors. Although it took no action for more than two years, in January 2014, the government began to raise natural gas prices for March to April

24 Rising domestic energy demand, particularly in Peninsular Malaysia, and LNG export contract obligations are placing pressure on the country s gas supply and driving Malaysia to actively seek investments for reservoir development. Several ongoing projects will expand natural gas production in Malaysia over the near term. Exploration and development activities in Malaysia continue to focus on offshore Sarawak and Sabah. Over the long term, Malaysia needs to attract higher levels of investment and technical capabilities to develop deepwater fields and those containing high levels of carbon dioxide and sulfur. Demand for natural gas-fired power, especially in Peninsular Malaysia, decreased in 2015 as a result of the reductions in price subsidies and the subsequent increase in coal usage as a cheaper source of energy. This drop is Malaysia-Thailand Joint Development Area expected to be a near-term phenomenon because Malaysia s coal capacity eventually cannot support the rising energy demand and environmental commitments. As a result, natural gas power demand is expected to increase again. However, gas demand for industrial development is likely to remain strong going forward as the government pursues greater economic development. One of the most active and prolific areas for natural gas exploration and production is the Malaysia-Thailand Joint Development Area (MTJDA), located in the lower part of the Gulf of Thailand and the northern part of the Malay Basin. The area is divided into three blocks, A-18, B-17, and C-19, and is administered by the Malaysia-Thailand Joint Authority (MTJA), with each country owning 50% of the MTJDA s hydrocarbon resources. According to the MTJA, 27 natural gas fields were designated by 2014, including nine fields each in Block A-18, Blocks B-17 and C-19. Production at Block A-18 started in 2005 and has a contracted level of about 290 billion cubic feet per year (Bcf/y) of processed natural gas. Block B-17 and Block C-19 came online by From 2010 to 2026, Blocks B-17 and C-19 are contracted to deliver 120 Bcf/y for the first 10 years then 90 Bcf/y for the remaining 6 years. Overall, average natu- 22 March to April 2018

25 ral gas production from MTJDA was slightly higher than 400 Bcf/y in 2015 and Block B is expecting development of its gas fields in 2017, with first gas deliveries in MTJA continues to explore the area to discover more hydrocarbons. stream assets supplying the MLNG liquefaction terminals. Shell and PETRONAS signed three more oil and gas PSCs with PETRONAS in 2012 and stepped up drilling efforts to continue developing natural gas and condensate production offshore Sarawak. The PSCs cover blocks SK319, SK318, and 2B in the Central Luconia Basin. Projects in Sarawak and Sabah Two natural gas fields in Sarawak (NC3 in block SK316 Most of Malaysia s natural gas production is offshore Sarawak and supports LNG exports from Bintulu. PETRO- NAS and other oil companies have made several discoveries of natural gas reserves since 2010 and commenced production from several fields, offsetting some of the declining production from mature gas basins in Peninsular Malaysia and in the shallow water blocks in Sarawak. Historically, Shell and PETRONAS have been the key developers of up- and Kanowit field in block SK306) began production to serve as feedstock gas for the new liquefaction terminals commissioned in Block SK316 holds three key fields that will supply the newly commissioned ninth train of the existing MLNG terminal. PETRONAS began producing natural gas from the first field (NC3) at the end of 2016 and expects to bring the other two fields (NC8 and Kasawari) online by However, PETRONAS is considering sell- March to April

26 ing up to 49% of the Kasawari gas project, which contains an estimated 3.2 Tcf in deepwater natural gas resources. The Kasawari field has elevated levels of carbon dioxide, so development requires advanced technologies. PETRONAS is seeking a skilled partner who can efficiently develop the Kasawari field in a more competitive gas price environment. Output from the Kanowit field began at the end of 2016 and is the initial feedstock for Malaysia s first floating liquefaction terminal. The Kanowit field is part of the larger Kumang Cluster, which began producing natural gas in The state of Sabah also holds reserves that are already under production or are scheduled to come online by A consortium consisting of PETRONAS (40%), ConocoPhillips (30%), and Shell, the operator, (30%), are developing three contiguous natural gas and condensate fields, including Kebabangan, Kamunsu East, and Kamunsu East Upthrown Canyon (KBB Cluster) in the northwestern Sabah state. The KBB cluster is estimated to hold 4.7 Tcf of gas. KBB production began in late 2014, and the KBB floating platform has a design capacity of 300 Bcf/y for natural gas, 80,000 b/d for crude oil, and 22,000 b/d for condensate. The platform acts as a hub for the development of these deepwater gas fields and ties in the Malikai crude oil field that came online at the end of Newfield Exploration, which recently divested its Asian upstream assets, made a significant gas discovery in the SK- 310 PSC offshore Sarawak in The company claimed the find could boost gas resources by 1.5 Tcf. In 2014, SapuraKencana Petroleum, a Malaysia oil services com- Other upstream developments offshore Sabah include the Kinabalu Non-Associated Gas project and the Rotan field in Block H. The Kinabalu project contains two natural gas fields and is scheduled to come online in mid Rotan and adjacent fields, operated by Murphy Oil in partnership with Pertamina of Indonesia and PETRONAS, have an estimated 1 Tcf of reserves. These fields are located far offshore from existing infrastructure on the coast of Sabah and are slated to supply Malaysia s second floating liquefaction terminal by pany, purchased Newfield s Malaysian upstream assets and now holds 30% of the SK-310 Block, while PETRONAS Transportation and Trade and Mitsubishi have 40% and 30% shares, respectively. SapuraKencana reported that it plans to bring the PSC s first field, B15, onstream towards the end of 2017 and the B14 field around In addition, SapuraKencana announced a significant gas reserve discovery in the PSC for block SK408 in 2016, signaling more near-term natural gas development potential in Sarawak. Malaysia has one of the most extensive natural gas pipeline networks in Asia, totaling about 1,530 miles. The Peninsular Gas Utilization (PGU) project, completed in 1998, expanded the natural gas transmission infrastructure on Peninsular Malaysia. The PGU system spans 1,550 miles and has the capacity to transport 730 Bcf/y of natural gas. Other gas 24 March to April 2018

27 pipelines run from offshore gas fields to gas processing facilities at Kertih. A number of pipelines link Sarawak s offshore gas fields to the Bintulu LNG facility. However, limited gas distribution coverage exists in much of the Sarawak and Sabah states. network of gas pipelines. Because of Malaysia s extensive natural gas infrastructure and its location, the country is a natural candidate to serve as a hub in the ongoing TAGP project, which currently has 2,250 miles in place of the proposed 2,800 miles of pipelines. Malaysia began exporting natural gas to Singapore through a pipeline in Singapore currently has two contracts to import 84 Bcf/y of gas from Malaysia, but its imports dropped to 44 Bcf in 2015 because Singapore imports natural gas through its new LNG terminal. Natural gas pipelines between West Natuna, Indonesia and Duyong, Malaysia were installed in 2002, and Malaysia began importing natural gas from Indonesia in In 2015, Malaysia imported around 90 Bcf of natural gas from Indonesia. The Trans-Thailand- Malaysia Gas Pipeline was commissioned in 2005 and The Sabah-Sarawak Integrated Oil and Gas Project, installed in 2014, includes the 318-mile onshore Sabah-Sarawak Gas allows Malaysia to transport natural gas from the Malaysia- Thailand JDA to its domestic pipeline system. Pipeline (SSGP) and can transport about 365 Bcf/y of gas from Sabah s offshore fields to the PETRONAS LNG complex in Bintulu for liquefaction and export. Some natural gas from the terminal is also reserved for fueling downstream industrial projects and for power generation in Sabah. Other pipelines link natural gas fields located offshore Sabah to the Labuan Gas Terminal. Malaysia is the world s third-largest exporter of liquefied natural gas, the second-largest oil and natural gas producer in Southeast Asia, and strategically located amid important routes for seaborne energy trade. The Association of South East Asian Nations (ASEAN) is promoting the development of a Trans-ASEAN Gas Pipeline system (TAGP) aimed at linking ASEAN s major gas production and consumption centers by 2020 through a March to April

28 References EIA Energy Commission of Malaysia Export.gov HIS Energy IEA International Monetary Fund Investivine LNG World News Malaysia Energy Commission MPRC MTJA Oil & Gas Journal PETRONAS Rigzone The Star Malaysia remains a key global LNG exporter as the third-largest exporter after Qatar and Australia in Malaysia is developing sizeable reserves in its eastern region and has expanded its export capacity in However, growing natural gas supply shortages in demand centers in Peninsular Malaysia have prompted PETRONAS to construct the country s first LNG import terminal in this western region to augment natural gas supply from pipelines. Even with expanded LNG facilities in Johor and Sabah, Malaysia is expected to gain smaller increments or even lose market share due to fierce competition from other LNG-exporting countries within the region. In 2016, Malaysia shipped about 1.2 Tcf/y of LNG and accounted for 10% of LNG exports worldwide. Key importers of Malaysia s LNG are Japan (62%), South Korea (16%), China (11%), and Taiwan (10%). Most of Malaysia s LNG is sold through medium- or long-term supply contracts with traders or utilities in these countries. Malaysia also has sold LNG cargoes to PETRONAS LNG Limited, a trading company based in Malaysia, which ships spot LNG cargoes to many locations around the world. Have you read our other magazine? see us on the web at 26 March to April 2018

29

30 project news Bids & Pieces SOUTHEAST ASIA Eni Announces Development Plan Approval INDONESIA Eni announced the approval of the Plan of Development (POD) for the Merakes field located in the East Sepinggan PSC in the Makassar Strait, offshore East Kalimantan, Indonesia. The Minister of Energy has granted the approval 28 March to April 2018

31 and Mineral Resources of the Republic of Indonesia, just 3 months after the submission of the plan and less than eleven months after Eni started production from its deep water operated asset in Indonesia, the Jangkrik fields the project. Merakes is another outcome of the Eni near field exploration and appraisal strategy. We are proud of Eni s partnership with Indonesia, a key country in the company s global strategies», said Eni s CEO, Claudio Descalzi. complex in the Muara Bakau PSC. Eni is the operator of East Sepinggan The Merakes field that is estimated to hold about 2 trillion cubic feet of lean gas in place is located in 1500 meters water depth, 35 kms South West of the Jangkrik Floating Production Unit (FPU). The field has been discovered by the Merakes 1 well in 2014 which encountered lean gas in world class reservoir quality sands of Pliocene age. In January 2017, Eni successfully drilled and tested the appraisal well Merakes 2, recording excellent gas deliverability. The proximity of Merakes discovery to the Jangkrik FPU will allow Eni to maximize the synergies with existing nearby infrastructures as well as to reduce costs and time of the execution of this second deepwater development in Indonesia. Claudio Descalzi, CEO, Eni The POD approved today foresees the drilling and completion of six subsea wells and the construction and installation of subsea systems and pipelines which will be connected to the Jangkrik FPU. The gas will then be shipped through the existing pipelines from the Jangkrik FPU to the Bontang LNG Processing facility operated by PT Badak in the East Kalimantan. Merakes production, likewise that of Jangkrik will contribute to the life extension of the Bontang LNG facilities, one of the world most reliable LNG processing plant which supplies LNG to both the domestic and export markets. The approval of the Merakes POD is a milestone for the development of our most recent discovery in the Kutei Basin. It is a fundamental step to progress towards the Final Investment Decision of PSC through its subsidiary Eni East Sepinggan Limited which holds 85% Participating Interest while Pertamina Hulu Energy holds the remaining 15%. MALAYSIA Sapura Energy to Develop SK408 Gas Fields Sapura Energy Berhad has announced that its wholly-owned subsidiary, Sapura Exploration and Production (Sarawak) Inc. (formerly known as SapuraKencana Energy Sarawak Inc.; Sapura E&P ) and its partners, PETRONAS Carigali Sdn Bhd and Sarawak Shell Berhad, have taken Final Investment Decision ( FID ) to develop the Gorek, Larak and Bakong fields as phase 1 in the SK408 Production Sharing Contract. March to April

32 The FID follows the Field Development Plan approval from Petroliam Nasional Berhad ( PETRONAS ) and concurrently, the signing of the key terms to the gas sales agreement for phase 1 of the SK408 gas field development. The development of the SK408 gas fields further strengthens Sapura Energy s position in Malaysia as a significant partner and supplier of natural gas to one of the world s largest LNG production facilities, the PETRONAS MLNG complex in Bintulu, said Tan Sri Dato Seri Shahril Shamsuddin, President and Group Chief Executive Officer, Sapura Energy Berhad. The fields under the SK408 gas field development project are part of the discoveries made by Sapura E&P in its 2014 drilling campaign. The fields will be developed as three separate wellhead platforms tied back to the existing processing facility and to the MLNG complex. The SK408 gas fields will be Sapura E&P s second major upstream gas development project in East Malaysia, after the successful development and commencement of production from the SK310 B15 gas field. The final investment decision represents a critical milestone as we further progress towards unlocking the value of our gas fields thus, providing clear visibility of our long-term gas monetisation plans. With the recent extensive addition to our exploration acreage in Mexico and New Zealand, the Group has been able to geographically diversify our E&P segment and put in place a wellbalanced portfolio across exploration, development and production phases, said Tan Sri Shahril. Sapura E&P is the development and production operator of the Larak and Bakong fields while Sarawak Shell Berhad is the development and production operator of the Gorek field. Sapura E&P has working interest with partners PETRONAS Carigali Sdn Bhd and Sarawak Shell Berhad. SINGAPORE Keppel On Track to Deliver South East Asia s First LNG Powered Tug Keppel Offshore & Marine, through its wholly owned subsidiary, Keppel Singmarine, is on track to deliver South East Asia s first dual-fuel LNG tug to Keppel Smit Towage on time and with a perfect safety record. The vessel was named KST Liberty at a ceremony held at Keppel Singmarine, with Mr Loh Ngai Seng, Permanent Secretary at Singapore s Ministry of Transport as the Guest of Honour. The 65-tonne bollard pull LNG dual-fuel Azimuth Stern Drive (ASD) tug was built to Keppel s proprietary design which won the Outstanding Maritime R&D and Technology Award at the 2015 Singapore International Maritime Awards. Mr Loh Ngai Seng said at the ceremony, Today s christening of KST Liberty marks an important milestone in Singapore s journey to make LNG bunkering available at our port as early as I congratulate Keppel O&M and Keppel Smit Towage for taking the lead, under MPA s LNG Bunkering Pilot Programme, to build and operate Singapore s first LNG-fuelled vessel. Such partnerships bring us closer to our goal of cleaner and more sustainable marine fuels. 30 March to April 2018

33 Mr Abu Bakar, Managing Director (Gas & Specialised vessels) of Keppel O&M, said, We are pleased to support Keppel Smit Towage and the industry s push towards adopting LNG as marine fuel with this upcoming delivery of South East Asia and Singapore s first LNG-powered tug. Our award-winning dual-fuel tug design offers more economical operations with efficient fuel consumption; a simplified bunkering process; optimised deck space that increases the safety and comfort of the crew; and ease of operations. One of seven dual-fuel vessels we are building, Keppel O&M has developed various solutions that are able to meet different needs along the LNG value chain. Smart designs were incorporated to enhance the tug s safety and comfort. The LNG fuel is carried in containerised, type-c ISO-certified tanks on the main deck, and re-fuelling can be done by truck to ship operations or replacing the empty tanks with replenished ones. It is equipped with an innovative and patented LNG vaporiser which is compact and cost-effective. Mr Romi Kaushal, Managing Director of Keppel Smit Towage added, This is a state-of-the-art tug, with environmentally-friendly features that exceed the requirements of the International Maritime Organisation s (IMO) global cap of 0.5% on the sulphur content of marine fuel that comes into force on 1st January, It will have substantially reduced CO2 emissions relative to traditional tugs and be a much welcomed green initiative. KST Liberty will also increase our capabilities as the fitted LNG tanks will allow for extended harbour operations without the need for re-fuelling, enhancing operational efficiency. It is also more compact, compared to tugs of the same bollard pull, providing enhanced maneuverability. We have built a strong partnership with Keppel over the years who have demonstrated their ability to design and deliver quality vessels that meet our needs. Shell will be supplying the LNG fuel to KST Liberty while FueLNG, a joint venture between Keppel O&M and Shell Eastern Petroleum (Pte) Ltd., will be providing the LNG bunkering services. The LNG bunkering will be conducted at Jurong Port which is able to support LNG bunkering operations. THAILAND Longitude Concludes Pre-Decommissioning Plan Contract for PTTEP Longitude Engineering, the specialist engineering consultancy and part of the London Offshore Consultants (LOC) Group, has developed a cost effective decommissioning barge concept for the safe removal of small oil and gas platforms for the PTT Exploration and Production (PTTEP), a subsidiary of the Thai state owned oil company. The primary aim of the works was to develop a viable and cost-effective alternative to conventional reverse installation through the use of heavy lift crane barges, for the removal of the topsides and jackets. The focus being the removal of of PTTEP s minimum facilities platform assets in the Gulf of Thailand, which have topside weights up to 800 tonnes and jacket dry weight up to 1000 tonnes. March to April

34 Longitude s contract was to deliver the conceptual naval, structural, mechanical and electrical engineering, along with outline operational procedures, schedule and CAPEX & OPEX costing for the new removal concept. The developed solution is a barge concept that utilises reverse float-over and on-board lifting methods to remove both the topside and substructure utilising the same vessel. For the development of the primary float-off lifting system, Longitude partnered with German-based hydraulics specialist, Bosch Rexroth, to develop a heave compensated hydraulic lifting and skidding system. VIETNAM Vietnam Scraps South China Sea Oil Drilling Project the country s southeastern coast following pressure from China, the BBC reported on March 23. It would be the second time in less than a year that Vietnam has had to cancel a major oil development in the South China Sea under pressure from China. The move comes as Repsol was making final preparations for commercial drilling. A rig, the Ensco 8504, was scheduled to depart from Singapore for the drill site on Thursday, the report said, citing an unnamed energy industry source. The cancellation could cost Repsol and its partners US$200 million (S$262 million) in sunk investment, according to the BBC. Repsol and PetroVietnam executives could not immediately be reached for comment. The Vietnamese foreign ministry did not immediately respond to an ed request for comment. Block 07/03 in the Nam Con Son basin, 440 km off the coast of Vietnam s southern city of Vung Tau. The block lies near the U-shaped nine-dash line that marks the vast area that China claims in the sea and overlaps what it says are its own oil concessions. The field can produce 25,000-30,000 barrels of oil and 60 million cubic metres of gas a day, Vietnamese news provider Cafef.vn reported last month. Repsol spent around 33 million euros (S$53.4 million) on exploration in Vietnam last year, according to the company s 2017 profit and loss statement. The Red Emperor site is considered by Repsol s top management as one of the company s future growth projects. Repsol, which has a per cent stake in the project signed a 384 million euro rental contract for a rig to start work on a Vietnamese site in 2019, according to the statement. Vietnam s state oil firm PetroVietnam has ordered Spanish energy firm Repsol to suspend its Red Emperor project off Red Emperor, known in Vietnamese as the Ca Rong Do field, is part of 32 March to April 2018

35 innovation and technology-driven philosophy and reinforcing its quality and efficiency enhancements. SOUTH KOREA THE ORIENT CHINA CNOOC Starts Production from Weizhou 6-13 Oilfield CNOOC Limited has announced that Weizhou 6-13 oilfield has commenced production ahead of schedule. Weizhou 6-13 oilfield is located in Beibu Gulf in the South China Sea with an average water depth of approximately 35 meters. In addition to fully utilizing the existing facilities of Weizhou 12-1 oilfield, the project has also built one wellhead platform. Currently, there are seven wells in production and the project is expected to reach a peak production of approximately 9,400 barrels of crude oil per day in 2019, exceeding its ODP approximately 3,000 barrels of crude oil per day. Weizhou 6-13 oilfield is an independent oilfield in which the Company holds 100% interest and acts as the operator. Mr. Yuan Guangyu, CEO of the Company, said: Weizhou 6-13 oilfield not only commenced production ahead of schedule, but also exceeded its ODP s estimates in both reserves and production. This is attributable to the Company s efforts in strengthening of its Russia Could Build Korea Pipeline A decade-old idea of a Russian gas pipeline to South Korea via North Korea could be revived if the security situation on the Korean peninsula improves, South Korea s Foreign Minister Kang Kyung-wha said. Should the security situation on the Korean Peninsula improve, we will be able to review the PNG [pipeline natural gas] business involving the two Koreas and Russia, South Korea s news agency quoted Kang as saying at a forum on regional energy cooperation in Seoul. Furthermore, if the North participates in talks on Northeast Asia energy cooperation, it would serve as a catalyst that helps ease geopolitical tensions in the region, South Korea s top diplomat noted. March to April

36 Russian giant Gazprom had the idea to deliver 10 bcm of natural gas to the resource-poor and import-dependent South Korea by pipeline, but its route has to pass through the territory of North Korea. Russia and South Korea signed a road map in 2011, but have not advanced beyond that, due to the tense regional situation. The ideas behind the pipeline look very difficult to implement, especially given the complex political-military context continuing on the Korean peninsula, and the obvious political risks. However, if there is political will and a mutual commitment, this project could take place, strengthening not only energy, but also military and political security in this rather turbulent region, Gazprom said in a corporate newsletter back in October INDIA ONGC To Raise Output from KG Basin ONGC is planning to increase its oil production by 17% and gas output by 24% from 2019 as it starts commercial production from its deep-water block in Krishna Godavari (KG) Basin. Confirming the development, ONGC chairman Sashi Shankar told The Hindu, We have seen around 7% growth in gas production in over the previous year. We will increase oil production by 17% and gas production by 24% from 2019 onward, in a phased manner. The development comes at a time when India s oil production had hit a seven-year low, while gas production saw first growth in six years. SOUTH ASIA In , India s gas production rose 2.35% to 32,649 mmscm. ONGC, with 7% growth in its gas production, contributed 23,429 mmscm, or 72%, to India s gas production. In , India s oil production dipped 1% in to 32,642 million tons, contin- 34 March to April 2018

37 uing its falling trend from 2012 when the oil production was 34,869 million tons. ONGC, which produces about 60% of India s crude oil, saw production stagnating at 20,370 million ton. The independent Scientific Inquiry into Hydraulic Fracturing has concluded the challenges and risks associated with any onshore shale gas industry in the NT can be appropriately managed. Territory businesses, contractors and workers are counting on the quick ramp up of the onshore gas industry to get the Territory moving again, Mr Gallagher said. Mr Gallagher said With exploration and appraisal success, the NT s McArthur Basin has the potential to do for the NT and Australia what the shale gas revolution has done for America, providing the competitive advantage to breathe life back into energy-intensive industries and generate wealth for the nation. THE PACIFIC AUSTRALIA Australia s Northern Territory Gives Green Light to Shale Gas Santos welcomes the Northern Territory Government s decision to implement the prerequisite conditions for recommencement of onshore gas exploration by the end of Santos CEO and Managing Director Kevin Gallagher said This is a great outcome for Territory communities because it will reinvigorate the economy there, generating jobs, local business opportunities and the social investments that gas companies make to help build a better future for the communities in which we operate. Kevin Gallagher, Santos, CEO and Managing Director Opening up access to this clean energy resource in the Territory is a great outcome for national energy security, potentially attracting new energy-intensive industries to Darwin and supporting new and expanded pipelines connecting to the east coast domestic gas market, Mr Gallagher said. There is a window of opportunity to also grow LNG exports as global supply gaps open up in the early to mid-2020s. Implementing the conditions for onshore gas exploration by the end of 2018 and getting the regulatory framework in place to allow onshore gas development by 2021 is vitally important to deliver a viable onshore gas industry as well as the desperately-needed economic and social benefits Territorians are counting on. March to April

38 Industry news Scene & Heard The Plan for Comprehensive Restructuring PVN Vietnam Oil and Gas Group (PVN) has sent an official letter to the Ministry of Industry and Trade on the plan for comprehensive restructuring PVN in period, in which there is a proposal to promulgate the amended Petroleum Law with the specific provisions for oil and gas exploration and exploitation in the direction of maximally applying the conditions of the specialized law in conformity with international practice. The contents of the letter include the following issues: The problems that PVN faced recent years are: i) in administration, although the internal regulatory systems are relatively sufficient and regularly updated but there is still lack of synchronization and did not keep up with fluctuations and changes of market economy, ii) The organization system has not been streamlined, duplicated multi-level, the responsible clues do not thoroughly handle the problems, there is a lack of close coordination between the specialized departments, iii) In investment activities, the portfolio management is unprocessed and unprofessional, the investment is spread out, resulting in low capital mobilization and investment efficiency, iv) the financial and cost management is without the system and timely decisions. At the some subsidiaries there are no norms, costs and debt management is not good v) The 36 March to April 2018

39 human resource training and developing implementation is slow then plan. Training activities cannot follow-up the specific characteristics of the PVN. The scientific research and technological applying have also many inadequacies. The view-point of PVN in this case is to concentrate in strong developing the organic and mutual link of the value chain of oil and gas exploration, exploitation and processing into the industry in order to bring into full play the strengths and advantages of the sector and increase the competitiveness in the country and participate in investment to the oversea countries PVN will continue to divest from the service bases (before and after 2020 as soon as possible) and from the electricity bases (before and after 2025 as soon as possible). PVN will also reallocate, optimize resources between production and business activities through equitization, divestment, M&A, new investments under the market mechanism, take efficiency as the core targets and eliminate internal competition Production and business operation is also reorganized for reducing the dependency and at the same time, perfecting the management system according to international standards. The PVN restructure will be carried out by two phases: In the first phase ( ) PVN would complete equitization in 3 companies as BSR, PVP and Pvoil. PVN would also prepare the conditions for equitization in PVEP as soon as possible after 2020, merger PVU and VPI into the Petroleum Institute (expected by 2020), the divesting in the units, making healthy of and restructuring financial situation in units/projects with losses. In phase 2 ( ), PVN will continue to maintain the main investment in 4 key areas but reduce the dominance, take only dominance (> 50%) for gas exploration and exploitation. PVN continues to increase market capitalization in petroleum exploration, exploitation, processing and electricity generation. PVN should withdraw all capital from service units, except for high-grade petroleum technical services for upstream. After 2025 to 2035, PVN continues to maintain its organic linkage in three main areas: oil and gas exploration and exploitation and processing, specialized high-tech services for oil and gas direct exploration and exploitation. In the period from now to 2020, PVN proposes to the National Assembly, the National Assembly Standing Committee, and Government to consider and promulgate a number of specific regulations on petroleum activities, which are applicable to projects in oil and gas exploration and exploitation, managing oil and gas contracts, costs, sharing interest, extracting funds and mechanism for tax definition for oil and gas project development. PVN asks Ministry of Finance to make mechanism for extracting the reserves to offset risks in oil and gas exploration operation with a 30% pre-tax profit, and mechanism to establish a fund for oil and gas exploration and exploitation with a rate of 17% of overturn from oil and gas projects (except VSP); to allow PVN to retain a minimum of 32% of petroleum interest of the Host Country from Petroleum Products Sharing Agreements and to consider supplementing PVN s provisions for oil and gas revenues, excluding the expense for PVN to carry out actual special tasks and 100% profit from the annual activities of Vietsovpetro Joint Venture. March to April

40 PVN suggests the Ministry of Industry and Trade to consider and submit to competent authorities specific mechanisms to attract foreign investment in petroleum activities in the country, taking priority into deep water, offshore, sensitive areas, the small fields and the fields with marginal economic conditions. S. Korea Revises Up LNG Demand Forecasts on Plan to Reduce Coal, Nuclear South Korea has revised up its LNG demand projections for the next several years on the back of its efforts to reduce reliance on coal and nuclear for power generation, the energy ministry said recently. LNG demand is now forecast to grow to million mt in 2031, up 11.1% from this year?s estimated million mt, the Ministry of Trade, Industry and Energy said in its Long-term LNG Supply Plan. LNG demand for power generation is projected to increase 0.26% each year on average to million mt in 2031, up from million mt estimated for Demand for retail gas for households and businesses is forecast to rise 1.24% annually to 23.4 million mt in 2031, up from million mt estimated for 2018, it said. The forecast puts total LNG consumption growth at 0.81% annually over the next 13 years, well below an annual average rate of 5.1% the past 13 years. The new forecasts reverse the trend projected in the previous Long-term Supply Plan in December 2015, when the ministry said LNG demand would decrease to million mt in 2022 and million mt in 2029, compared with 2014 consumption of million mt, due to lower power generation demand. But LNG demand is expected to get stronger as the country is shifting away from coal and nuclear fuel, the ministry said. President Moon Jae-in, who took office in May last year, has vowed to increase power generation using LNG and decrease the use of coal and nuclear in order to address mounting public concerns over air pollution and nuclear safety. Under the country s long-term Basic Blueprint for Power Supply released in December last year, LNG s share in actual electricity production would climb to 18.8% in 2030, up from 16.9% in Coal s share in the power mix would fall to 36.1% in 2030 under the blueprint, from 45.3% in 2017, and nuclear would decline to 23.9% in 2030 from 30.3% in 2017, while the share of renewables would rise to 20% in 2030, compared with 6.7% in As part of effort to ensure a stable supply, South Korea will diversify LNG imports sources, the MOTIE statement said. More than 80% of import volumes in 2017 came from five countries - Qatar, Australia, Oman, Malaysia and Indonesia - up from 78.9% in 2012, which means South Korea s dependence on the five suppliers grew in the past five years. We will look for the potential of Russian and US LNG projects as part of efforts to reduce the heavy reliance on several existing producers, a ministry official told S&P Global Platts, noting Russia s Yamal LNG project and the US shale boom. South Korea, the world s No. 3 LNG importer, will also step up cooperation on flexible contracts, volume swapping and facility sharing with Japan and China, the world?s biggest LNG importers, the ministry said. 38 March to April 2018

41 We will seek to have more flexibility in mid- and long-term contracts through cooperation with major LNG buyers, the ministry said in the statement. The main sticking points in fixed LNG supply contracts are: take or pay clauses that force buyers to pay for cargoes even if they do not need them; destination clauses that prevent buyers from selling on cargoes; and oillinked pricing. The ministry said South Korea would also build more storage facilities as part of efforts to secure stable supply. State-owned Korea Gas Corp is pushing to build its fifth LNG storage terminal by 2031 with a capacity of 2 million kiloliters, which it said would help the country store 3.56 million kl of LNG that year. To that end, some Won 5.8 trillion ($5.46 billion) will be spent, according to the ministry. Platts Maersk Drilling and Maersk Supply Service Form JV Decommissioning Company A 50:50 joint venture (JV) between Maersk Drilling and Maersk Supply Service will leverage the companies heritage of over 50 years of safe and efficient operations to provide decommissioning services to oil and gas operators. After decades of production, an increasing amount of offshore oil and gas fields are approaching the end of their economic life. In the North Sea alone, more than 400 fields are expected to cease production by 2026 at an estimated cost of USD 56 billion. Globally, over 700 fields are expected to require decommissioning. Drawing on Maersk Drilling and Maersk Supply Service s high-quality assets and technical capabilities, the JV will initially offer bundled solutions for up to 80% of the process required in decommissioning an oil field. The bundled solutions will, in addition to project management, cover work scopes such as plug and abandonment of wells, towage of floating units and removal of subsea infrastructure. In the longer term, the JV plans to provide the full end-toend process of decommissioning. With the growing need for decommissioning mature fields, governments and oil and gas operators are looking for experienced partners to manage and perform this challenging task. By leveraging the strong track record of the two companies, as well as our complementary asset base and competencies, we can lower the risk and reduce the overall cost for the customers, says Jørn Madsen, CEO of Maersk Drilling. Maersk Drilling and Maersk Supply Service have both done decommissioning work for various clients. Since 2016, Maersk Supply Service has been project managing and executing the full scope of decommissioning services for the Janice, James and Leadon subsea fields in the UK North Sea for the operator - former Maersk Oil, now Total. While Maersk Drilling did the plug and abandonment (P&A) for the James and Leadon wells, Maersk Supply Service provided the marine asset coverage on all three subsea fields and took on the responsibility for the engineering, subcontractor management, offshore planning, interface management and associated logistics, as well as the disposal of recovered facilities from the seabed through management of waste disposal contractors. March to April

42 companies since 2001, most recently acting as site manager for the construction of the Ailsa FSO in Singapore, for the Culzean project. Steen Karstensen, CEO of Maersk Supply Service and Jorn Madsen, CEO Maersk Drilling. By combining our marine knowledge and experience from recent decommissioning projects, we can provide oil and gas operators bundled solutions with one point of contact for the majority of decommissioning work scope. With the experience and asset base brought to the JV by both companies, and the team to see it through, I am confident that the decommissioning JV can offer attractive and flexible solutions Jens Klit Thomsen, currently Head of Decommissioning Business Development at Maersk Supply Service has been appointed Chief Commercial Officer of the JV as of 1 April. Carsten Sander Jacobsen has been appointed Chief Technical Officer as of 1 May. He is currently Head of P&E Engineering in INEOS Denmark, responsible for field development and decommissioning activities. to the market, says Steen S. Karstensen, CEO of Maersk Supply Service. An individual corporate brand for the JV Maersk Drilling and Maersk Supply Service will invest an equal amount in the JV will be established in the coming months. over the coming year. The joint investment is approximately USD 20 million covering the first years of operations. In addition, the JV partners will provide assets to the JV through standard commercial conditions. With the projection of adding up to three new projects per year after 2020, the JV s revenue is expected to grow steadily over the first five years. The JV will not impact the ongoing work in A.P. Moller - Maersk to establish new ownership structures for each of the partner companies. Susan Dio Appointed Chairman and President of BP America BP has announced that Susan Dio has been appointed chairman and president of BP America Inc., BP s chief representative in the United States, from 1 May The foundation of the JV will be a lean and scalable base organisation, covering only core capabilities and drawing upon support from Maersk Drilling and Maersk Supply Service. The JV will be headquartered at the Maersk Drilling and Maersk Supply Service joint headquarters in Lyngby, Denmark. Lars Banke has been appointed Chief Executive Officer of the JV and will join the company from Total in June Lars has a background in mechanical engineering from Denmark s Technical University and has worked in various Maersk 40 March to April 2018

43 Dio succeeds John Mingé, who will move to chair a study by the National Petroleum Council (NPC) into CCUS technologies and their potential deployment. He will retire from BP in March Bob Dudley, BP group chief executive said: Susan s breadth of operational and commercial experience gained with BP around the world including leading our global shipping business, running a major refinery, and managing a chemical plant make her ideally-suited for the key role of representing BP in the US. The US is a vital part of BP we have invested more than $100 billion here since All our businesses, from exploration to refining to renewable energies, operate at scale in the US and together they make up the largest portfolio of businesses we have anywhere in the world. Susan Dio Susan Dio, a chemical engineer by training, has been chief executive of BP Shipping for the past three years, responsible for BP s shipping business worldwide, including its fleet of over 70 operated and time-chartered vessels. In this time, she led the review and reset of the organization s strategy and operations and oversaw the ongoing renewal of the fleet the largest such programme in BP s history. Previously during her 33-year career with BP and heritage companies, she held a series of senior commercial and operating roles in the US, UK, and Australia. The NPC s study into CCUS technologies was directed by US Secretary of Energy Rick Perry and the NPC asked that Mingé take on this distinguished role. The study will consider CCUS technologies, the factors and policies required for their successful deployment, and possible pathways for integrating CCUS at scale into the energy marketplace, particularly in the petroleum industry. In addition to his work on the study, Mingé will continue to provide BP with strategic advice on work to advance the energy transition. John Mingé has headed BP America since February He led the recovery of BP s reputation in the US through the years following the Gulf of Mexico oil spill, leading a stronger focus on safety and reliability and ensuring that obligations to federal and state governments and Gulf Coast communities were met. More recently he headed BP s response to the severe impact of Hurricane Harvey on the Houston area and BP s US headquarters. Mingé had previously spent four years running BP s business in Alaska and, earlier in his almost 35-year career with BP, held executive and engineering posts in the US, UK, Vietnam and Indonesia. Bob Dudley said: John has been a superb leader of BP America through a period of great challenge. He has driven a culture of safe, reliable and compliant operations throughout our businesses, worked steadily to rebuild our reputation, and been a tireless advocate for BP and our industry in Washington and across the US. The effective use of CCUS technologies will be key to meeting the world s ambitions to reduce carbon emissions and it is vital that we understand these technologies and how they can best be integrated with our energy systems. I am certain that the study John will lead will make an important contribution to developing this understanding. March to April

44 Flow Measurement Analysing the Flow Jason Yew, Sales Director KROHNE- Petromin Marine & How does KROHNE play a part in storage or tanking Offshore (PMO) : operations? EMAS Oil & Gas Sdn Bhd, spoke to Petromin Marine & Offshore about the measurement technologies one of the industry leaders have to offer. Key are ultrasonic and Coriolis meters. Jason Yew (JY) : We, KROHNE, deal with measurements. In terms of tanks we have custody transfer and inventory management packages like level monitoring radar. We recently launched the 80GHz radar. We are also able to aid in the loading and unloading processes. For example, we ve got a huge order for the RAPID project for our ultrasonic metres to deal with the measurements at the loading jetty. Vopac and Dialog have adopted our technology. I don t consider ultrasonic to be new technology anymore. I ve been explaining to clients for 15 years on how this technology can help their bottomline. On the liquid side, ultrasonic has been around for 20 years already and we are already in the second generation of the technology. Unfortunately, in Asia they still view ultrasonic as a new technology and some even say its unproven; however, Petrobras has been using it from day one for their floaters. Petrobras uses ultrasonic technology for all their offloading. Our first installation for Statoil was in The North Sea Committee is very impressed with this technology and have given the go ahead for full implementation. PETRONAS, for their RAPID project, now uses the latest technology for its measurements moving on from conventional, mechanical measurements. 42 March to April 2018

45 PMO : What new technology is KROHNE working on now? PMO : Comparing ultrasonic to the Coriolis meter, what would be the pros and cons of each? JY : Right now, we are very excited about our bulk transfer, JY : Ultrasonic has no pressure drop because is full bore and in terms of fluid diagnostics the ultrasonic is far more advanced. The Coriolis meter is more robust and more convenient. Due to the nature of the two different processes this is to be expected. Therefore, which technology is used would depend on the client requirements. In essence, KROHNE has tailor made these two solutions to meet clients varying requirements. The 16-inch Coriolis is a real breakthrough because it minimizes the issue of drop in pressure and is almost reaching the FPSO, FSO offloading capacity. And the 16-inch, for the same class, we were the first to launch it. Coriolis meter. The Coriolis meter is a very compact solution. The Coriolis metre looks at frequencies of the tube vibrations and thus establishes the measurements. The tricky thing is that if you look at steel, the tensile strength will actually vary according to temperature and pressure. When that happens, your resonant frequency gets affected. After years of R&D we have come up with a solution to tackle this problem to have very reliable pressure and temperature corrections which makes this a self-calibrating, self-correcting technology. We recently launched a 16-inch straight tube Coriolis metre. Installation is simple and its meant for large capacity transfer of hydrocarbons. The compactness and convenience of the straight tube solves a lot of problems for the clients. It can fit on a vessel itself or PMO : Does the launch of this 16-inch meter put you significantly ahead of your competitors? at the jetty. Furthermore, there is no maintenance cost and so from an operational expenditure point of view its good for the client. PMO : You mention negligible maintenance but what about robustness? JY : Due to patents we have registered, in how we solved the problems associated with a bigger tube, it will take competitors some time to find alternative solutions. So this means that currently we do hold an advantage. In fact, surprisingly, in 2018 we got an order for 16 pieces in China. Considering how conservative the oil and gas JY : Its very robust. Outside of a lightning strike which will burn all the electronics, this will run forever. Of course, there are also diagnostics for the meter, so operators can easily determine the condition of the meter. In fact, the North Sea Committee s proposed guidelines inform operators that instead of performing maintenance by schedule, they should run the diagnostics and if the results are perfect there is no need to perform maintenance until the next schedule. We are now trying to bring this concept to Asia. We are not saying this is the right way, we are just sharing ideas with the industry. Malaysia is actually currently writing new standards for the Coriolis meter and they too are promoting diagnostic analysis. industry is in implementing breakthrough technology, this was very good news for us, a very pleasant surprise. Jason has been in the Instrumentation industry for over two decades and currently holds his position as Sales Director since July Between 1998 and 2000, he worked in the Food and Beverage manufacturing industry. In 2002 Jason joined KROHNE s Oil and Gas Division. He has held several positions within the group, culminating to his current position responsible for Sales and Business Development in Malaysia and the South East Asia region. He has participated in many flow measurement conferences in South East Asia, particularly in Malaysia. March to April

46 Gas-Powered Engines Feature Low-Speed Low-Pressure X-DF Technology When the development of the twostroke low-pressure DF lean-burn technology started, the extensive experience from Wärtsilä s four-stroke developments could be utilized as a base in several technology areas. These include engine automation and control, pilot injection, gas supply system and engine testing to mention a few. It was already in the 70s and 80s of the last century when first trials with gas fuelled two-stroke engines took place in the former Sulzer Diesel company. Both combustion principles, low-pressure Otto cycle and high-pressure Diesel cycle were tested and evaluated, but none of the concepts achieved a breakthrough in the market at that time. After a new assessment of the market requirements and available technologies, the development of the low-pressure dualfuel technology for low-speed two- stroke engines was restarted in 2011, and a designated test engine was installed in the engine laboratory in Trieste, Italy. As a first step, one cylinder of the RT-flex50 based diesel engine was converted to enable it to operate on gas, while the other five cylinders remained running on diesel with the original equipment. This setup was used to develop and validate the basic concepts for gas admission and ignition, and to define the control principles. This process work and initial results were presented in a paper at the last CIMAC Congress in Shanghai in In 2013, the full engine was equipped with more industrialized equipment for gas operation, upgrading it to an excellent development tool for full scale engine operation tests. Focus was directed to the development of engine components, performance and control system features, finally resulting in the X-DF solution which is commercially available today. As an imminent need for larger DF engines was recognized in the market, the technology was transferred to the larger bore engine types X62DF and X72DF, and a full scale 6X72DF technology demonstrator engine was set up at WinGD s licensee Diesel United Ltd. (DU) in Aioi, 44 March to April 2018

47 Japan (Figure 1). DU has been the cooperation partner in this development since the beginning of the project. The engine went into operation in early 2015 and was demonstrated to numerous representatives of the shipping world in April The fact that the low-pressure technology has proven to also be perfectly suitable for larger bore engines has triggered an enormous interest for the X-DF solution in the market. As demonstrated on test and customer engines, WinGD s X-DF engines are characterised by stable combustion, inherently low NOx emissions and high overall system efficiencies as well as safe gas operation. In terms of NOx, WinGD X-DF engines undercut IMO Tier III limits for Emission Control Areas (ECAs) by considerable margins without any additional measures, such as EGR or SCR while running on gas. Moreover, with the low-pressure gas admission, the gas fuelling system does not require any high-pressure compressors, considerably reducing equipment costs, on-board energy consumption and maintenance during operation. Additionally, a large supplier base is available for gas supply systems, as the components are like systems installed on numerous four-stroke DF engines, proven in thousands of hours in field operation. Due to possible fast combustion or pre-ignition, the maximum brake means effective pressure (BMEP) of the X-DF engines has been limited to 17.3 bar, as explained in the chapter about fundamentals of combustion. This results in a reduced power density of the DF engines compared to the 21 bar maximum achievable BMEP on today s modern two-stroke diesel engines. However, the market response shows that the engines are commercially attractive, due to low investment cost and the superior overall system efficiency. Figure 1. W6X72DF technology demonstrator The X-DF Concept The low-pressure dual-fuel technology developed by WinGD for its X-DF engine series builds on Wärtsilä s long experience with what has become a well-proven industry standard on medium-speed dual-fuel engines. In contrast to high-pressure gas injection engines, which operate on the Diesel cycle, WinGD s low-pressure X-DF engines work on the lean-burn Otto cycle when operated in gas mode i.e. ignition of a compressed lean air/gas mixture by injection of a very small amount of liquid pilot fuel. Gas Admission System The gas distribution and admission system has been specifically designed for the requirements of the two-stroke engine. Gas is supplied from aft- or free end and distributed in gas manifolds along both sides of the engine to feed gas to each cylinder. To ensure fast depressurization of the distribution pipes in case of a malfunction, both gas manifolds are equipped with a fast shutoff valve on the inlet side, and a fast vent valve at the end of the pipe (Figure 2). All gas-containing pipes are of double wall design and made from stainless steel, in order to fulfil requirements of marine classification societies. March to April

48 Figure 2. Gas distribution and admission system Each cylinder is equipped with two hydraulically actuated gas Figure 3. Gas admission valve section admission valves (GAV), injecting gas through the cylinder liner wall directly into the cylinder. Since the gas is injected before the actual compression starts, a low gas pressure of bar is sufficient to achieve a homogenous air/gas mixture, even at full engine load. The system is designed for a maximum pressure of 16 bar to cope with lower heating values down to 28 MJ/Nm3, while maintaining similar gas injection durations and ensuring unchanged maximum power output. Excellent results have been achieved in terms of functionality and reliability of the valves in rig and engine testing. After passing the gas admission valve, the gas fuel is injected into the cylinder by gas admission bores, which pass through the cylinder liner wall. Both, CFD simulations and engine testing have confirmed that a careful design of the admission bores in terms of dimensioning and geometry is essential for an optimized performance of the engine. The nozzles have a strong A new design (Figure 3) was developed in-house for the gas influence on mixture homogeneity. admission valves, to satisfy the specific requirements of the twostroke engines. Attention was given to simplify the valve concept Pilot Fuel Ignition System to maximize reliability and ensure simple maintenance. Hydraulic power is delivered from the existing servo oil circuit, also used for actuation of the exhaust valves, eliminating the need for an additional hydraulic system. For good long-term stability and tightness, a robust valve design with a spherical valve seat was chosen. Sealing oil is used to separate the gas side from the servo oil side, as well as to lubricate the valve guide. For increased operational safety, the valves are equipped with a lift measurement sensor, which allows the engine control system to take immediate action in case of a malfunction of a valve or a related control signal. The cartridge-type design allows replacing all the moving parts without removing the valve housing or the gas piping system. This ensures short downtime periods for repairs or replacement of the valves and reduces the risk of gas leakages induced by maintenance. To ignite the lean air/gas mixture, with its high self-ignition temperature, the compression end temperature in the engine is not high enough to create sufficient reactivity. Direct injection of pilot fuel, based on common rail injection, has proven to be a reliable solution for medium-speed four-stroke engines. It provides a sufficient ignition stability with a minimum fuel quantity. For the two-stroke engines, a solution with a pre-chamber, shown in Figure 4, was developed. The pre-chamber concentrates the energy of the pilot fuel, leading to higher temperatures than in the main chamber. Thus, there is more margin for the self-ignition of the pilot fuel, giving a shorter ignition delay with less stochastic variations of the timing. For the same reason, the combustion duration is short, resulting in a rapid pressure increase in the pre-chamber. This creates a powerful torch, penetrating well into 46 March to April 2018

49 the main combustion chamber. This concept provides ignition energy well distributed in the combustion chamber, with minimized pilot fuel quantities of below 1% of the total energy input at full engine load, a level considerably lower than of any other system available on the market. Pilot fuel is supplied to each injector by a small-size common rail system. Fuel mode transfer to change from liquid to gas mode and vice-versa during engine operation Control of timing, duration and pressure for gas admission and pilot fuel injection Control of the exhaust waste-gate for adjustment of scavenge air pressure and lambda Knock and misfire detection and control, for combustion control and engine safety Compression and firing pressure balancing to optimize engine performance by balancing individual cylinders Additional monitoring features for enhanced operational safety Fundamentals of Combustion Unlike with the Diesel process, the heat release in the Otto process cannot be controlled by the rate of injection since all the fuel is admitted and mixed with air before ignition. In the Otto process, combustion is to some extent guided by the turbulence and swirl level during compression and combustion, but the basis for combustion control on a given engine design is the air/fuel (A/F) ratio of the mixture. Correct adjustment of the A/F ratio ( lambda ) together with correct ignition timing gives the optimum combustion speed, resulting in an operating point with best efficiency and lowest NOx emissions. The correct A/F ratio also enables the engine to run on high BMEP levels without pre-ignition, knocking or misfiring. Figure 4. Pilot fuel injector and pre-chamber Engine Control System There is a rich limit for the A/F ratio, which is to a certain extent depending on residual gas and lube oil content. If this limit is exceeded, the combustion will accelerate, increasing firing pressures and NOx formation. Further reduction of the A/F ratio may lead to spontaneous ignition prior to the pilot injection ( pre-ignition ) and/or may develop to a knocking combustion. The rich limit is defined by the firing pressure limit and the required knock margin. All WinGD two-stroke dual-fuel engines are operated by a UNIC-based engine control system. The UNIC control system is an embedded engine management system of modular design and is applied to a range of diesel engines in the latest X-engine series. For dual-fuel engines, the system is equipped with the following additional main functionalities for gas operation: Increasing the A/F ratio towards the lean limit will gradually slow down combustion, reducing efficiency and NOx, increasing combustion instability with growing risk for partial or complete misfiring (see Figure 5). At the same time, eventually, emission of unburnt fuel ( methane slip ) is increased. The lean limit is defined by the combustion instability, which is quantified as COV (Coefficient of Variation), the average variation of IMEP. A COV value of 2.5% is considered to be an industry standard. March to April

50 Turbo Charging and Control of Air/Fuel Ratio Figure 5. Lean-burn Otto combustion limits The gas composition has an influence on the operating window. The X-DF combustion layout is made to cover gas with a Practically, the A/F ratio is controlled by the scavenge air pressure, which is adjusted by a by-pass valve for the turbo charger turbine ( exhaust waste-gate ). The required scavenge air pressure depends mainly on the actual gas quantity injected which is dictated by the engine load biased with adjustments based on actual operating conditions like ambient temperature, pressure, etc. The target values for scavenge air pressure are defined in the parameter maps of the engine control system. Besides this, also the exhaust valve closing timing directly affects the A/F ratio (trapped air mass). minimum Methane Number (MN) of 80 without a reduction of the nominal engine output. Lately, engines have however been tested with full BMEP on MN 65. The engine control system detects, if the engine for some reason is not operated within the target operating window. By Oil mist from cylinder lubrication has proven to have a minor influence on the combustion. Even if some of the lube oil droplets are igniting during compression, the ignition energy of individual constant monitoring of firing pressures, fast combustion, excessive firing pressures and misfiring is detected. In addition, the engine is equipped with conventional knock sensors to provide additional safety. droplets is too small to ignite the lean air/gas charge and have an influence on the combustion. Therefore, standard cylinder lubrication oils with a low base number (TBN 15 25) can be used for gas operation. The area between the rich and lean limit is defined as the operating window. The optimum operating point has the best trade-off between efficiency and NOx, while leaving sufficient margin to both limits. In Figure 6, typical cylinder pressure curves are presented for rich, normal and lean combustion. Figure 7. Control of Air/Fuel ratio Pilot Injection/Ignition With a powerful ignition source as described above, the lean limit is extended and the engine can be run at a higher A/F ratio. This results in unchanged high efficiency while both, unburnt hydrocarbon emissions (methane slip) and NOx formation are reduced compared to an open chamber pilot injection. Figure 6. Examples of rich, normal and lean combustion 48 March to April 2018

51 Co-located with: Abu Dhabi International Petroleum Exhibition & Conference November 2018 Supported By Host City Knowledge Partner Official Broadcast Partner Official Media Partner ADIPEC Organised By The Global Offshore Meeting Place BOOK YOUR SPACE NOW Why Exhibit? JOIN one of the region s largest congregations of offshore vessel owners, operators and charterers including OSV, Barges, AHTS, Seismic, Jack up rigs and many more. GAIN cutting-edge knowledge and share best practices at the Offshore and Marine Conference in the venue s unique waterfront location in Hall 15. CAPITALISE on US$25bn worth of offshore investments in the region. Network and do business with an international offshore and marine audience from 45+ countries. GENERATE direct sales, boost your brand image and become part of the world s largest energy event outside of North America. MEET with key departments from NOC s, IOC s, EPC s and service companies to discuss projects, updates and an exchange of industry knowledge. LAUNCH new products, build prospect databases and maintain relationships with existing customers. SHOWCASE your products and services to 15,000+ marine and offshore industry professionals. NEW FOR 2018 Commercial Dive Zone ADIPEC recognises that an extensive range of commercial diving equipment supports the offshore and marine sector. A specialist zone for the world s subsea and offshore solution providers within Offshore & Marine will enable exhibitors to reach the right people to transform their business and boost their profitability. Offshore projects are increasing in the region, ADNOC Offshore operates the Upper Zakum, Lower Zakum and Umm Shaif fields in the UAE, they produce 1.4 million b/d collectively. Exhibiting companies who support the underwater operations of the global Offshore & Marine sectors will liaise with the industry s most influential stakeholders in a dedicated zone highlighting their expertise. Offshore & Marine In Numbers: 15,000 GROSS SQM SPACE 15,000 OFFSHORE & MARINE ATTENDEES 150+ EXHIBITING COMPANIES CONFERENCE DELEGATES BOOK YOUR SPACE NOW adipec.sales@dmgeventsme.com Offshore & Marine Exhibitors Include Quality Marine Services

52 With an optimized configuration of the pre-chamber and the pilot injection nozzle, the combustion is relatively insensitive to changes of the pilot fuel injection pressure and duration/ quantity. Since the pilot mainly serves as a trigger for the start of combustion, any excessive pilot fuel quantity will not help to speed up the combustion or make it more complete. - starting the gas injection as late as possible to minimise the risk that gas is getting in contact with hot rest gas in the upper end of the combustion chamber, which could result in self-ignition and early combustion - by the above, direct methane slip into the exhaust can be avoided - ending the gas injection early enough to create an air buffer on piston top. By this, the piston top land is not filled with air/gas mixture during compression, and also this potential source of methane slip is minimised In addition to creating an air/gas charge with maximum homogeneity (yet stratified), the gas admission needs to: - be accurate and repeatable from cycle to cycle Figure 8. Comparison of pre-chamber vs. open chamber pilot - have shortest possible opening/closing ramps - have a minimum dead volume downstream the valve Figure 9. Example of pressure trace in pre-chamber Figure 10. Gas admission valve lift curves related to boundaries Gas Admission Future Developments The geometry and location of the gas injection nozzle is designed with the target to maximise the homogeneity of the air/ gas mixture, hence avoiding rich zones that would be prone to self-ignition and result in high combustion temperatures and NOx formation levels. While the X-DF technology is released for commercial engines, the development work is continuing with the target to evaluate future potential for increased fuel efficiency in gas and diesel mode, as well as for higher maximum power output. Additionally, new features will be introduced, giving further benefits to operators, such as a fuel sharing mode. This development to On the other hand, a certain stratification is also strived for, for the following reasons: only mention one example will allow LNG carriers to burn gas and liquid fuel simultaneously and by this achieve the desired 50 March to April 2018

53 speed even with limited amount of natural boil-off gas, eliminating the need to additionally force boil-off. Because a considerable part of the fuel is combusted in a diffusive regime, the fuel sharing mode will be tuned to be IMO Tier II compliant. In Figure 11, a comparison of cylinder pressures and rate of Engine type Bore x Stroke Max. Power (R1) Max Speed (R1) Max. BMEP (R1) DU - WinGD 6X72DF 720 x 3086 mm 19.35MW 89 rpm 17.3 bar heat releases is shown for different fuel ratios. The gas combustion in mixed mode still reaches the same maximum rate of heat release, while the diesel fuel portion leads to an increased total combustion duration. Overall, it can be concluded that the combustion in the fuel sharing mode is an interpolation of full gas and full diesel combustion, which is also reflected in the cylinder pressure curves. The same is valid for NOx emissions, which range from well below IMO Tier III levels in gas mode to Tier II levels in diesel mode. Turbocharger 2 x ABB A270-L or 2 x MET 60MB Table1. Main parameters of the 6X72DF test engine Fuel gas for operation of the test engine is supplied from the low-pressure fuel gas supply system (FGSS). LNG, which is stored in an insulated tank, is pressurized by forced evaporation and volumetric expansion of the gas in the tank. The pressurized LNG is evaporated in a heat exchanger by hot water. The gas supply Figure 11. Comparison of cylinder pressures and rate of heat release with different fuel modes under comparable conditions pressure can be changed flexibly up to 16 bar. During engine testing, fuel gas is typically supplied at a pressure of 12 bar. Two large buffer tanks are installed in the gas supply line to minimize the variation of the gas composition, which can be induced by a sudden change of the gas demand. The fuel gas composition is analysed by a gas chromatograph (SHIMADZU GC20B). Based on the composition, the lower calorific heating value (LHV) and the Methane Number (MN), which indicates the knock resistance, are calculated with the software AVL Methane. The engine test results presented in this report are carried out with an approximate Methane Number of 67. X72DF Test Results Test Engine and Plant The main parameters of the 6X72DF test engine are shown in Table 1. The earlier described X-DF technology is applied to this engine. For testing purposes, this engine was designed to have some flexibility to vary the scavenging port position and size, the gas injection nozzle, the number of pilot injectors and the Figure 12. Low-pressure fuel gas supply system (FGSS) for test engine turbocharger type. March to April

54 Performance Test Results Exhaust Emissions As shown in Figure 13, the NOx emissions of the engine in Diesel mode complies with IMO Tier II NOx regulations. In gas mode, the NOx levels can be reduced to well-below-imo Tier III NOx limits without exhaust gas after treatment, which is a unique feature of the low-pressure DF technology. Figure 14. Measured THC emissions (methane slip) Fuel Consumption As shown in Figure 15, energy consumption in gas mode (including pilot fuel) was measured within tolerances as specified in GTD, WinGD s performance documentation tool. Only at full engine load, the limit is slightly exceeded. Further optimization is expected to bring the full load consumption to target values. Figure13. NOx emissions At part load, consumption figures well below the specified values could be achieved, resulting in a benefit in real operation Results of methane slip measurement are shown in Figure 14. of a vessel. Initially, the level was expected to be higher, due to the risk of direct methane slip during the scavenging of the cylinder. However, by adjustment of the gas injection timing, the scavenging process is completed (exhaust valve closed) before the air/gas mixture reaches the upper part of the cylinder, and direct methane slip is therefore eliminated. The remaining methane slip relates to flame quenching on combustion chamber walls and dead volumes in piston top land etc. In comparison, the level is lower than on typical four-stroke lean-burn Figure 15. Measured energy consumption in gas mode gas engines, because of lower engine speed, longer time for oxidation and a larger combustion space, with a favourable volume-to-surface ratio. A major milestone was achieved in terms of pilot fuel consumption. As shown in Figure 16, it was possible to reduce the pilot injection quantity to record low levels of below 0.5% of the total fuel input at full load, while maintaining stable operation of the 52 March to April 2018

55 4 th LNG Marine Fuel Forum Theme: Emerging Opportunities, Innovation & Operation 4-5 September 2018 Singapore CALL FOR PAPERS The Patron & Technical Committee Members of the 4 th LNG Marine Fuel Forum 2018 cordially invite you to submit your abstract for technical presentations at the conference with the theme, Emerging Opportunities, Innovation & Operation. Patron: HE Anita Nergaard Norwegian Ambassador to Singapore Keynote Speaker: Mr. Lasse Karlsen Director, Norwegian Maritime Authority CONFERENCE CHAIRMAN & TECHNICAL COMMITTEE WONG TOON SUAN, MD of Oneblue; Executive Advisor of ILO, National University Singapore: Chairman, LNG Marine Fuel Forum ROLV STOKKMO, Poten & Partners TESCH ALEXANDER, Director, Marine & Offshore, MTU Asia Pte Ltd ABUL BASHAR MD MASUM REZA, Principal Research Engineer, Keppel Offshore & Marine Technology Centre ELSIE TANG, Senior Consultant, Shipping Advisory, Marine Advisory, DNV GL (Asia Pacific) PER CHRISTER LUND, PhD, Science and Technology Counsellor, Norwegian Embassy in Singapore Prabjot Singh Chopra, Manager, Technical & Business Development, SeaTech Solutions International (S) Pte Ltd JULIEN BOULLAND, LNG Specialist / Sr. Naval Architect, Bureau Veritas Marine (Singapore) Pte Ltd Prof. Karimi Iftektar Abubakar, Professor, National University Singapore Yoong Hui Chia, CEO of Ascenz Calvin Chua, Senior Development Partner Marine and Offshore, Enterprise Singapore Day 1-9AM-12.30PM : Opportunities & Business Opening Welcome Address will be given by HE Anita Nergaard, Norwegian Ambassador to Singapore & Conference Patron and Keynote Presentation by Mr. Lasse Karlsen, Director, Norwegian Maritime Authority and Mr. Walter Purio, CEO, LNG Marine Fuel Institute, Australia Update by Oil Companies Regulatory Policies Ship & Vessel Owner s Perspective Project Financing Legal Issues Market & Trends Day 1-2PM-5.30PM : Innovation & Technology Challenges and issues in transition to upcoming IMO regulations Infrastructure requirements and challenges Tank design and operation: LNG carriers, bunkers, and LNG-fueled ships Engine design & Fuel gas supply system BOG management Bunkering system compatibility Pressure management in the tanks Control of ship movement Design and optimization of bunkering process SOP, safety issues and standards in Conference highlights Invitation to submit Abstract Submission and Guidelines Please register your speaker and send your abstract, which should not exceed 300 words to Ms Mary at info@media-buz.com. The committee members will review the written papers to ensure that the content is in line with the objective of the conference. To register as delegate, please info@media-buz.com with the following details: Full name, Job title, Company; Address, Telephone; Mobile, address Abstract Submission deadlines: 30 May 2018 Selected papers will be published in Petromin Marine & Offshore magazine. bunkering Cost effective and safe solutions Design of control systems Technology for cargo containment system Environmental challenges in bunkering Multipurpose bunkering ship design Retrofitting of ships Software tools and simulators Training and educating operators Case studies on bunkering Day 2-9AM-12.30PM : Operation Operational experience on LNG bunkering from the pioneer Norway The first purposely built LNG bunker vessel s first few bunkering operations TR Singapore Technical Reference on Competency requirement for personnel involved in LNG bunkering Metering and custody transfer experiences Panel Discussion on LNG bunkering operational challenges and mitigations Day 2-2pm- 5.30PM : Workshop on Training, Safety, Human Factors, Risk Assurance etc Note: Your Photograph and Bio data should accompany this submission of abstract for the purpose of producing Conference promotional publications. Sponsorship & Exhibitor Opportunities A wide range of sponsorship opportunities are available. Sponsors and exhibitors will be recognized in conference materials and at the event. Organized by: For more information on Sponsorship & Exhibition packages, please Mary at info@media-buz.com

56 engine. When running in diesel mode, the pilot injection system is still running to keep the injector nozzle holes clean, though with further reduced injection quantity. Lean-burn pre-mixed combustion typically results in higher cycle-to-cycle fluctuation of cylinder pressures compared to diesel combustion, as also known from four-stroke lean-burn gas engines. Figure 18 shows that the cycle-to-cycle fluctuation of maximum cylinder pressures in gas mode is higher than in diesel mode. However, as shown in Figure 19, indicated mean effective pressure (IMEP) fluctuation in gas mode is as small as in diesel mode. Therefore, the engine speed deviation shown in Figure 20 is on well acceptable level, comparable to the deviations in diesel mode. Figure 16. Measured pilot fuel consumption in gas mode Diesel fuel consumption in the IMO Tier II compliant diesel mode was measured to be within the specified range, with margin at part load operation. Combustion Behaviour Figure 17 shows an example of cylinder pressures over the load Figure 18. Cycle-to-cycle fluctuation of Pmax range in gas mode. The combustion is free of knocking or preignition even with the low Methane Number of 67. Maximum cylinder pressure and the gradient of pressure rise are below design limits. Therefore, similar component reliability as on a diesel engine can be expected. Figure 19. Cycle-to-cycle fluctuation of IMEP Figure 17. Cylinder pressures 54 March to April 2018

57 further investigate the dynamic behaviour of the engine. The deviation of the speed setpoint was set to +/- 4.3 revolutions at 80.5 rpm (75% of MCR power) as shown in Figure 22. The engine speed follows the speed setpoint without knock or misfire. This means that the engine shows a good transient response behaviour and can therefore withstand to rough sea conditions in gas mode. Figure 20. Engine speed fluctuation at 100% engine load Low Load and Wave Loading Operation Another unique feature of the low-pressure DF technology is the ability to operate at manoeuvring speeds (low load). Testing has confirmed that the X-DF engines can run stably at low engine loads without misfiring or instability. To achieve this, the strong Figure 21. Engine response under wave load condition ignition source from the applied prechamber system is essential. At the same time, the minimized pilot fuel amount results in a big enough gas amount for repeatable gas admission from cycle-tocycle. The minimum engine load in gas mode for X-DF engines is currently set to 5% of MCR and is likely going to be further reduced in the future. Reliable operation on gas under rough sea conditions is important for ocean going vessels. Under such conditions, waves and rolling motion of the ship induce load variations to the propeller, which directly transfer to the engine. For simulation of rough sea conditions, several tests were carried out on the engine test bed. Two examples are shown below: Figure 22. Engine response to a variation of the speed setpoint For the first time, the low-pressure DF technology has been successfully implemented on a large two-stroke marine engine. - At a constant engine speed setpoint, a torque fluctuation of the water brake was set to 9% at a period of 20 seconds, which was limited by the water brake capability (Figure 21). Thus, the engine could operate in gas mode continuously without knock or misfire. - In addition, a test with a variation of the engine speed setpoint was carried out in both, diesel and gas mode to Extensive R&D activities have brought the technology from a concept level to a solution ready for the market. This has been demonstrated in several Factory Acceptance Tests and the Type Approval Test of the RT-flex50DF engine. Additionally, it is shown in this paper that the technology could be transferred to the larger bore X72DF engine in a straightforward way and that the expected performance results were achieved. March to April

58 References and Bibliography [1] NYLUND I., OTT M. Development of a Dual Fuel technology for slow-speed engines CIMAC PAPER No. 284, CIMAC Congress, Shanghai, [2] INTERNATIONAL MARITIME ORGANIZA- TION, IMO, Revised MARPOL Annex VI, [3] INTERNATIONAL MARITIME ORGANIZATION, IMO, THE MARINE ENVIRONMENT PROTEC- TION COMMITTEE, Resolution MEPC.177(58) Amendments to the technical code on control of emissions of nitrogen oxides from marine diesel engines, NOx Technical Code [4] GTD, Program for calculating the performance of WinGD engines, or Based on the experience gained by this development, it can be concluded that the results build a solid base for further extension of WinGD s low-pressure dual-fuel technology to the full engine portfolio. Definitions, Acronyms, Abbreviations DF: Dual-Fuel LNG: Liquefied Natural Gas UNIC: Unified Controls (engine control system) CFD: Computational Fluid Dynamics GAV: Gas Admission Valve FGSS: Fuel Gas Supply System GTD: General Technical Data (engine performance documentation) ROHR: Rate of Heat Release COV: Coefficient of variation IMEP: Indicated Mean Effective Pressure This periodical thanks - Marcel Ott, Winterthur Gas & Diesel Ltd., Ingemar Nylund, Intec AB, Roland Alder, Winterthur Gas & Diesel Ltd., Takayuki Hirose, IHI Corporation, Yoshiyuki Umemoto, Diesel United Ltd. and Takeshi Yamada, IHI Corporation for providing this article for publication. BMEP: MN: MCR: TBN: ECA: EGR: SCR: NOx: SOx: THC: Brake Mean Effective Pressure Methane Number Maximum Continuous Rating Total Base Number Emission Control Area Exhaust Gas Recirculation Selective Catalytic Reduction Nitrogen Oxides Sulphur Oxides Total Hydro Carbon A/F-ratio: Air/Fuel ratio 56 March to April 2018

59 3 rd Tank & terminal Tech Asia 2018 Theme: Enhancing Tank Integrity 9-10 october Kuala Lumpur, Malaysia call for papers Keynote ADDRESS Tuan Haji Kamal Bahrin VP/CEO, PETRONAS GAS BERHAD PATRON Datuk. Kamarudin Zakaria Former VP, Group HSE, PETRONAS The Patron & Technical Committee Members of 3 rd TTTA 2018 ( Tank & Terminal Tech Asia ) cordially invite you to submit your abstract for presentation in the conference with the Theme, Enhancing Tank Integrity. In line with the theme, Industry Leaders will be invited to share their views in 3 panel session which are Desuldging, Cleaning & Inspection, DIgitization & Big Data For Tank Integrity & Process Safety Management Of Change For Tank-Farm. TECHNICAL COMMITTEE: Ir Alzakri Ekhwan, Custodian Engineer, Group Technical Solutions Petroliam Nasional Berhad (PETRONAS); Tank Farm Tech Asia, Conference Chairman Tan Lek Lek, Executive Director (Technical), Dialog E & C Sdn Bhd Sharul B A Rashid, Principal Engineer Instrument & Control, Petronas Penapisan (Terenggannu) Steve Klasnich, Process Safety Manager, Chevron International Pte Ltd Robin Essenius, COO/Member, CTS Group BV/EEUMA Sanjay Sharma, Head Facility Planning & HSSE, Reliance Industries Limited ABSTRACT SUBMISSION: The abstract, which should not exceed 300 words, should be sent to us via to Mary at info@media-buz.com or you may submit online at on or before 30 th April The Program Committee will review the written abstract / papers to ensure that the content is aligned with the objective of the conference. Please note that abstract / paper of a purely marketing / commercial nature will not be considered. All final papers must be written in MS WORD, to facilitate publication of selected papers in Petromin Hydrocarbon Asia Magazine. REGISTRATION: To register as a Speaker or Delegate, please Mary at info@media-buz.com with the following details: Full name; Job title; Company; Address; Telephone; Mobile; address. Conference Topics: Latest Innovation In Tank Design And Construction Maintenance Cleaning Best Practices And Techniques In Tank Desludging Tank Inspection Practices Tank Corrosion Prevention Latest Coating Technologies Safeguards Used In Preventing Tank Overfill Specific Risks And Safeguards For Pressurized Spheres And Bullets Containing LPG Best Practices In Preventing Static Electricity Incidents Safety Incidences / Case Studies (PSM Related) Ageing Tanks Common Problems And Methods Of Extending Tank Lives Tank Failures Common Root Causes, And Preventive Measures Tank Farm Automation Optimizing Efficiency Case Studies Of Process Safety Incidents Involving Tanks And Terminals Environmental Mishaps New Technologies In Cryogenic Tanks & Transport Problems In Using Existing Marine Vessels For LNG Storage Abstract submission deadline: 31 May 2018 Organized by:

60 Asia s technology information provider in the upstream, downstream and midstream sectors PETROMIN marine & offshore - The Asia/Pacific s first and most established oil & gas magazine covering exploration, drilling, production and transportation(upstream) for the past 43 years. The magazine now also covers maritime and shipping technologies. Published bi-monthly, PETROMIN Marine & Offshore has a vast readership in Asia. PETROMIN Marine & Offshore plays a pivotal role in providing up-to-date technical and business information in the form of in-depth and well-researched articles, and interviews with industry personnel. While maintaining our printed circulation, the magazine is also online where your advertisement is linked to your company s website. January/February 2018 Country / Regional Report Singapore Special Feature Floating Production & Storage Technology Propulsion Systems Bonus Feature Emissions Reduction March/April 2018 Country / Regional Report Malaysia Special Feature Gas-Powered Engines Technology Station-Keeping May/June 2018 Country / Regional Report Australia Special Feature Bunkering Vessels Technology Storage Technology Journal Advertising Petromin Marine & Offshore EDITORIAL SCHEDULE 2018 Advertising Rates Full Colour 1 x insertion 3 x insertion 6 x insertion Inside Front Cover S$3500 S$3100 S$2800 Inside backcover S$3000 S$2700 S$2400 Full Page S$3000 S$2700 S$2400 Half Page Island S$1800 S$1600 S$1400 Half Page S$1500 S$1300 S$1200 Quarter S$1000 S$900 S$800 Back Cover S$4500 S$4000 S$3600 Double Page spread S$5000 S$4500 S$4000 PLEASE NOTE: All advertising rates in Singapore Dollar All measurements below are width x height July/August 2018 Country / Regional Report Indonesia Special Feature Decommissioning Technology Digitalisation September/October 2018 Country / Regional Report Southeast Asia Special Feature HSE Technology Automation Systems Bonus Feature Smart Shipping November/December 2018 Country / Regional Report South Korea Special Feature Report Corrosion Control Technology Ballast Technologies Full Page (Trimmed Size) 210mm x 297mm +3mm bleed on all sides Island 1/2-page 118mm x 195mm Horizontal 1/2-page 180mm x 128mm 1/4-page 87mm x 113mm Advertisement production Ad copy is preferred in press-optimised pdf format (embedded images minimum 300 dpi) and materials created in other packages will need to be confirmed as acceptable. Please supply final version proofs. All components should be supplied in CMYK and not RGB with fonts embedded. Classified Advertising Full Colour yearly Classified Bronze - Size: 57mm x 35mm S$600 Classified Silver - Size: 57mm x 54mm S$900 Classified Gold - Size: 57mm x 73.5mm S$1200 PLEASE NOTE: All advertising rates in Singapore Dollar Please supply ad copy in minimum 300dpi tiff or jpg. Web Advertising Full Colour Monthly Top banner S$1200 Bottom Banner S$750 Small Box S$600 Large Box S$900 Please supply web banners as a gif, jpg. For circulation details and other information, visit our website For all advertising requirements and your business advertisement schedule please contact Mary at info@media-buz.com, Tel: ; Fax: Mediabuz Pte Ltd Business Reg.No M Tel: Fax: Website:

61 calendar of events 2018 June th Dynamic Positioning Asia Conference & Exhibitions June 2018, M Hotel, Singapore Contact: Mary Dela Pena Tel: info@media-buz.com Website: July September 2018, Singapore Contact: Mary Dela Pena Tel: info@media-buz.com Website: Asean Energy Week September 2018, IMPACT Exhibition Center, Bangkok, Thailand Contact: Jelly Rungphailin Sreehom Tel: marketing.thai@asiafireworks.com Website: This information is supplied as is. While every attempt has been made to ensure the accuracy of such information, the publisher does not accept responsibility for any loss or damage attributable to errors or omissions. Organisers are advised to check the information and to notify the magazine of any such errors or omissions. If is available, please also provide address. This listing is a free service to Petromin Marine & Offshore readers. To have your conference or exhibition listed please post, fax or details to Mary at info@media-buz.com. For latest information. Log onto & click on Events Calendar. 11 th RAMPS July 2018, Kuala Lumpur, Malaysia Contact: Mary Dela Pena Tel: info@media-buz.com Website: Tank Storage Asia September 2018, MBS Expo, Singapore Website: October 2018 INAMARINE July 2018, JIExpo Kemayoran, Jakarta, Indonesia Contact: Santi, Ms Tel: info@gem-indonesia.net Website: August 2018 IADC/SPE Asia Pacific Drilling Technology Conference and Exhibition August 2018, Bangkok, Thailand spekl@spe.org Tel: Website: september th LNG Marine Fuel Forum SIBCON (Singapore International Bunkering) 2-5 October 2018, Resorts World Sentosa, Singapore Website: 3 rd Tank Terminal Tech Asia October 2018, Kuala Lambur, Malaysia Contact: Mary Dela Pena Tel: info@media-buz.com Website: Asian Downstream Summit October 1 November 2018 Sands Expo & Convention Centre, Singapore Contact: Rahmah Ishak Tel: infoasia@clarionevents.com Website: March to April

62 Asia s technology information provider in the upstream, downstream and midstream sectors PETROMIN Hydrocarbon Asia has been serving the refining and petrochemicals industry for 27 years, with the focus on refining, gas processing and petrochemicals production. The content covers technology, best practices, case studies and interviews with industry personnel. The magazine is published quarterly. EDITORIAL SCHEDULE 2018 January - March 2018 Country / Regional Report Malaysia Special Feature HSE Technology Maintenance April - June 2018 Country / Regional Report Indonesia Special Feature Tank Storage Technology Heat Exchange July - September 2018 Country / Regional Report Singapore Special Feature Biofuels Technology Catalysts October - December 2018 Country / Regional Report China Special Feature Corrosion Under Insulation Technology Liquefaction Advertising Rates Journal Advertising Petromin Hydrocarbon Asia Full Colour 1 x insertion 2 x insertion 4 x insertion Inside Front Cover S$3200 S$2800 S$2500 Inside backcover S$2700 S$2400 S$2100 Full Page S$2700 S$2400 S$2100 Half Page Island S$1600 S$1500 S$1300 Half Page S$1300 S$1200 S$1100 Quarter S$900 S$800 S$700 Back Cover S$4000 S$3600 S$3200 Double Page spread S$4500 S$4000 S$3600 PLEASE NOTE: All advertising rates in Singapore Dollar All measurements below are width x height Full Page (Trimmed Size) 210mm x 297mm +3mm bleed on all sides Island 1/2-page 118mm x 195mm Horizontal 1/2-page 180mm x 128mm 1/4-page 85mm x 110mm Advertisement production Ad copy is preferred in press-optimised pdf format (embedded images minimum 300 dpi) and materials created in other packages will need to be confirmed as acceptable. Please supply final version proofs. All components should be supplied in CMYK and not RGB with fonts embedded. Classified Advertising Full Colour yearly Classified Bronze - Size: 57mm x 35mm S$600 Classified Silver - Size: 57mm x 54mm S$900 Classified Gold - Size: 57mm x 73.5mm S$1200 PLEASE NOTE: All advertising rates in Singapore Dollar Please supply ad copy in minimum 300dpi tiff or jpg. Web Advertising Full Colour Monthly Top banner S$1200 Bottom Banner S$750 Small Box S$600 Large Box S$900 Please supply web banners as a gif, jpg. For circulation details and other information, visit our website For all advertising requirements and your business advertisement schedule please contact Mary at info@media-buz.com, Tel: ; Fax: Mediabuz Pte Ltd Business Reg.No M Tel: Fax: Website:

63 ASEAN OWERex ASIA 2018 In conjunction with : Asia 2018 w w w. a s i a p o w e r e x p o. c o m w w w. a s i a e l e c t r i c e x p o. c o m w w w. r e n e w a s i a - e x p o. c o m S ept em b er I M P A C T E x h i b i t i o n c e n t e r, B a n g k o k, T h a i l a n d

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