Petromin

Asia's Exploration & Production Business magazine

MARCH/April 2014

PETROMIN

http://www.safan.com MCI (P) 128/03/2014 • PPS 1749/09/2013(025502) • ISSN 0129-1122 Published by AP Energy Business Publications Pte Ltd. 19 Kim Keat Road, #04-06 Fu Tsu Building, Singapore 328804. Printed by KHL Printing Co Pte Ltd

Serving Asia and the Middle East since 1974

AN ASIA PACIFIC ENERGY BUSINESS PUBLICATION

Offshore Drilling Going Deep

march/april 2014 VOL. 40 NO.02

Indonesia – The Fight for Growth .... pg08 Onshore: Old Dog Learns New Tricks .... pg22 Offshore Vessel Connectivity .... pg32

Asia's E & P and Pipeline Business magazine Incorporating: Asia Offshore Engineering

Reports Indonesia – The Fight for Growth Continues .................................... 8 Old Dog Learns New Tricks ......... 22 Oil and gas E&P started onshore and after decades of production is currently more often than not seen as a shrinking source.

New frontiers such as deepwater and FLNG have opened up as sources for hydrocarbons, thus marginalising onshore E&P. However, onshore E&P still has an important role to play in the never-ending drive for energy sources.

Offshore Key to Future Growth .................................................... 32 With easy oil being a thing of days past and the oceans and the artic regions considered to be the last bastions of virgin resources for oil and gas it is clear that offshore E&P is sure to grow. This report states in summary some of the points in favour of this view.

march/april 2014 VOL.40 No. 02

Although it has been around for some time it is still a sector that is very young and this article outlines some associated issues as well as technologies pertinent to the sector.

Offshore Vessel Connectivity Today and Tomorrow ................... 52 The maritime satcoms landscape is shifting with a new generation of services poised to come online. Offshore oil & gas users are today among the heaviest bandwidth consumers, with a diverse range of operations all depending on VSAT services to enhance applications from vessel and fleet management through to the delivery of seismic data.

Conferences & Exhibitions MODUC 2014 – A Resounding Success ........................................ 56

Bids & Pieces ............................. 36

INAMARINE 2014 ...................... 58

Scene & Heard ........................... 43

Regular Focus

Technology

Editorial ........................................ 6 Bids & Pieces ............................. 36

Unlocking Coalbed Methane ................................................... 46

Scene & Heard ............................ 43

With natural gas gaining recognition as a major source of energy the role of CBM has come into the spotlight.

Advertisers Index ........................ 60

Calendar of Events ...................... 59 Subscription Form ..................... 48A

We also publish

Official Publication for : Reliability, Asset Management & Safety (RAMS) Conference • Pressure Vessel and Heat Exchange Engineering Technology Asia Convention • Corrosion Management in Refineries and Process Plants • FLNG Technology and Unconventional Gas Asia Summit • Deepwater Technology and Offshore Support Vessel Asia C&E • Onshore Technology Asia C&E • Jack Up and Semi Submersible Technology Asia Summit • Corrosion Management, Welding and Composites Technology Asia Convention

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Editorial concept of PetroMin magazine

An Asia Pacific Energy Publication

PetroMin is now in its 40th year of existence. It is a magazine dedicated to the technology of the oil and gas industry in all its forms.

PetroMin is published by AP ENERGY BUSINESS PUBLICATIONS PTE LTD 19 Kim Keat Road #04-06 Fu Tsu Building Singapore 328804 Tel: (65) 6222 3422 Fax: (65) 6222 5587 Website: www.safan.com

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 you will find interviews, case studies and field reports written by our staff or technical correspondents. We also give to the IT, instrumentation and control of the upstream industry.

Now in its 40th year, PetroMin is a business publication covering the exploration, production and related activities of the oil and gas industry in the Asian, Asia-Pacific and Middle-eastern regions.

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 US$120. Please refer to the subscription form or contact the subscription department for further details at Fax: (65) 6222 5587.

Covering both offshore and onshore 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.

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@safan.com with your suggestions.

As the magazine is BPA audited, and our qualifying region is the Asia Pacific, we try to publish material of use to this region, but technology is global and we welcome contributions from anybody.

If there are aspects of the upstream industry you feel are missing from our coverage, please do e-mail us and tell us. We will do our best to supply coverage of that aspect in the future.

PetroMin – Asia's oldest, and only oil and gas technology journal published and printed in Asia.

The publisher does not assume any responsibility or liability for errors or omissions.

For Further information, please visit our web sites Printed in Singapore by KHL Printing Co Pte Ltd.

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PetroMin : Hydrocarbon Asia : http://www.safan.com PetroMin Pipeliner :

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Editorial Age Old Debate….

S

ince the late 1800s, when offshore drilling first started, there has been the debate of where the E&P focus and future should lay.

Initially, due to the comparative lack of knowledge and experience, the focus remained on onshore sources. However, with drilling now possible under thousands of feet of water, coupled with the fact that there is growing apprehension that most onshore sources have already been discovered, offshore E&P is seen as the torch-bearer for oil and gas.

My opinion, which I’ve found to be similar to that held by the majority of industry personnel through various discussions I’ve had, is that the two will have to co-exist for the foreseeable future with neither being discounted as a growth sector. Although most onshore fields have been discovered, which is not the case offshore, in terms of brownfield development there is certainly more potential onshore than offshore.

Another critical point is that technological developments may change the economic and operational viability of fields. For example, EOR has resulted in many fields being redeveloped to become significant contributors towards the global oil supply. Marginal field development also has more scope in the onshore sector than the offshore sector, although there is quite a bit of scope for offshore stranded gas production. EOR and marginal field development are areas which have been exploitable only in the last thirty years or so. The relevant fields were by and large closed off for production only to be reopened due to technological advances in these sectors. Similarly, a technological breakthrough (such as oil sands a few years ago) may switch future focus to onshore E&P.

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Publishers Eddie Raj/Executive Editor

Having said that, however, as things stand, the future does seem to point to offshore E&P. Deepwater production is starting to grow and contribute significantly; FLNG technology is making the exploitation of offshore gas more economically viable; and the amount of time and money spent on subsea R&D is staggering. At present our future energy security lies in unchartered waters, both literally and figuratively.

All this means that there is no point in arguing over which should be in the spotlight or which should be given precedence; the fact of the matter is that efforts need to be made both onshore and offshore to ensure that we are not driven back to the dark ages in the centuries to come. Currently there can be no winner in this debate.

We have produced this issue of PetroMin with this line of thought in mind. The features for this are Indonesia (Country Feature), Onshore E&P (Special Feature) and CBM (Technology Feature). Even at first glance one can tell that this issue focuses heavily on the onshore sector. To balance this we have incorporated a market report on offshore E&P as well as a technical article on offshore communications systems. Just like the oil and gas industry has to focus on both the onshore and offshore, we too have to ensure that our content is not tilted in favour of either of these sectors.

I leave you with these thoughts and hope, as always, that we have contributed in some way towards expanding PET your knowledge.

Vishnu Pillai Group Editor

Group Editor Vishnu Pillai Tel: 6222 3422 ext: 104 email: vishnu@safan.com Online News Editor Natalia Lim Tel: 6222 3422 ext: 108 email: natalialim@safan.com Graphic Artist Chua Ai Hwa Tel: 6222 3422 ext: 103 email: aihwa@safan.com Advertising Co-ordinator Mary Tel: Tel: 6222 3422 ext: 101 email: mary@safan.com Subscription / Circulation Khaleel Tel: 6222 3422 ext: 111 email: khaleel@safan.com Conference Co-ordinator Zaman Tel: 6222 3422 ext: 112 email: zaman@safan.com 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

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Indonesia – The Fight for Growth Continues

I

ndonesia is the most populous country in Southeast Asia and the fourth most populous country in the world, behind China, India, and the United States. Formerly a net oil exporter in the Organization of the Petroleum Exporting Countries (OPEC), Indonesia struggles to attract sufficient investment to meet growing domestic energy consumption because of inadequate infrastructure and a complex regulatory environment.

Despite their energy struggles, it was the world's largest exporter of coal by weight in 2012 and the fourth-largest exporter of liquid natural gas (LNG) in 2013. As Indonesia seeks to meet its energy export obligations and earn revenues through international market

Indonesia's total energy demand is closely linked to the country's economic exp a n s i o n . A c c o rd i n g t o t h e International Monetary Fund (IMF), Indonesia sustained re l a t i v e l y s t ro n g e c o n o m i c performance throughout the global recession, with an average gross domestic product (GDP) growth rate of just under 6% per year between 2008 and 2012. However, in 2013, GDP growth fell below 6%. Overall, the energy sector (including electricity) constituted 15.6% of Indonesia's GDP in 2012 and has held roughly constant at this level since 2005. Net foreign direct investment (FDI) more than

doubled between 2008 and 2012 but shrank by roughly 15% in 2013.

The energy sector continues to influence the economy to a large degree. Oil and gas alone constituted one-fifth of merchandise exports in 2012, according to IHS Global Insight. In addition, revenues from the oil and gas sector accounted for 24% of total state revenues in 2012. A combin a t i o n o f h e a l t h y g ro w t h , market reforms, and a stable government has encouraged rapid investment, particularly in the commodity sector.

Moody's Investors Service and Fitch Ratings both upgraded Indonesia's sovereign risk rating to an investment grade status between late 2011 and early 2012.

On the other hand, investment in infrastructure was around 3 % o f G D P i n 2 0 11 , well below most of Indonesia's neighb o r s , a c c o rd i n g t o IMF data. The government signed land reform legislation in late-2011 to pave the way for more private sector infrastructure

R e p o r t Country Report CIA 2005

sales, the country is also trying to meet demand at home.

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development. It also unveiled a new development strategy in 2011 (Master Plan for Economic Expansion and Acceleration 2011-2025) that e m p h a s i z e d m o re p r i v a t e sector involvement in infrastructure expansion, such as wider use of public-private partnerships in the oil and g a s s e c t o r. D e s p i t e t h e s e efforts, many infrastructure projects continue to be delayed, and regulatory challenges and uncertainties have reduced predictability for foreign investors.

Oil

Indonesia ranked as the 24th-largest crude oil producer in the world in 2013, accounting for about 1% of world production. After oil was first discovered in 1885 in northern Sumatra, the hydrocarbon sector became an important part of Indonesia's economy.

Indonesia suspended its membership in OPEC in 2009, after joining in 1962.

This exit was prompted by growing internal demand f o r e n e rg y, d e c l i n i n g p ro duction (most notably in mature fields), and limited i n v e s t m e n t t o i n c re a s e c a pacity. Indonesia currently i m p o r t s c ru d e o i l a n d re fined products to meet demand. The country straddles the Strait of Malacca, one of the world's major oil transit chokepoints.

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Indonesia's declining oil production and rising domestic demand resulted in the country's exit from OPEC in 2009 and higher levels of petroleum imports to meet demand.

IOCs in the Indonesian oil market include Chevron, Total, ConocoPhillips, ExxonMobil, and BP. Chevron is the largest oil producer in Indonesia, accounting for about 39% of the country's crude production in 2013. PT Pertamina (Pertamina), Indonesia's state-owned integrated energy supply company, accounted for approximately 17% of domestic crude prod u c t i o n t h ro u g h 2 0 1 2 , a c cording to government reports, making the company the second-largest oil producer, followed by Total and ConocoPhillips, respectively the third and fourth largest producers. Other national oil companies (NOCs) such as the China National Offshore Oil Corporation (CNOOC) a n d S o u t h K o re a ' s K N O C a l s o h o l d s i g n i f i c a n t u pstream assets.

In addition to its upstream activities, Pertamina operates nearly all of Indonesia's refinery capacity, procures crude oil and products imports, and supplies petroleum products to the domestic market. Pertamina's monopoly in the re-

tail market ended in 2004, but the company continued to be the sole distributor for subsidized fuels until early 2010.

Pertamina must balance its own needs as a corporation, t o i n c re a s e e x p o r t p ro f i t s with its mandate as a national oil company charged with meeting domestic demand.

The Indonesian Ministry of Energy and Mineral Resources is responsible for entering into production sharing contracts (PSCs) with interested oil companies. Indonesia's 2001 Oil and Gas Law significantly restructured Indonesia's upstream oil and gas sector, transferring the upstream regulatory role from Pertamina to BPMigas, a state-owned legal entity that was tasked with managing and implementing PSCs. Although Pertamina continues to be wholly state-owned, the 2001 law also established it as a limited liability corporation in 2003.

BPMigas was established following the passing of the 2 0 0 1 O i l a n d G a s L a w. I n November 2012, Indonesia's Constitutional Court deemed upstream regulator BPMigas to be unconstitutional, based on the regulator's role that limited the state full access to maximize the benefits of natural resource management for Indonesia's welfare, and ordered it to be dissolved.

The Energy and Mineral ReVisit our website at www.safan.com

sources Ministry temporarily t o o k o v e r re g u l a t o r y f u n c tions through a special task force, SKK Migas, which will operate until the government amends the 2001 legislation.

SKK Migas is tasked with managing and implementing PSCs, determining sellers of government shares of oil and gas, and increasing oil and gas production for domestic demand. The President of Indonesia is ultimately responsible for formulating oil and gas regulatory policy, while parliament possesses the duties of oversight and consent.

Following a corruption case w i t h i n S K K M i g a s a n d a rrest of its former chairman in late-2013, the entity lost the right to market the country's unused oil and gas designated for domestic use within Indonesia. The government transferred exclusive domestic marketing rights to stateowned Pertamina.

Indonesia possessed 3.6 billion barrels of proven crude oil reserves as of January 2014, down from 4 billion barrels at the beginning of 2013, according to Sources. According to SKK Migas, reserve replacement of oil is 52% as a result of declining investment in oil exploration, especially in deepwater blocks.

Petroleum and other liquids (or total liquid fuels) production declined from a high of nearly 1.7 million b a r re l s p e r d a y ( b b l / d ) i n

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1991 to an estimated 928,000 bbl/d in 2013. Crude oil and lease condensate production made up 834,000 bbl/d of this total, a level below the government's original 2013 target of 900,000 bbl/d. The total number of new exploration and development wells fell to 840 in 2012, declining by 12% from 2011, according to IHS Global Insight.

The government's annual crude oil production targ e t , w h i c h h a s b e e n o v e rstated each year since 2009, is 870,000 bbl/d in 2014, although Indonesia reported that it plans to reduce this target to 820,000 bbl/d. Several factors put downward pressure on Indonesia's oil output each year, including: licensing approvals at the regional level of government, land acquisition and permit issues, oil theft in the South Sumatra region, aging oil fields and infrastructure, and insufficient investment in unexplored reserves.

Indonesia's two oldest, largest producing fields are Duri and Minas, located on the eastern coast of Sumatra in the South Sumatra Basin.

D u r i b e g a n p ro d u c i n g i n 1952 and currently averages around 140,000 bbl/d, according to Facts Global Energy (FGE). The Minas field began production in 1955 and currently produces around 190,000 bbl/d, according to

FGE. Chevron operates both fields with a 100% working interest. Production at both fields is declining, even with enhanced oil recovery (EOR) techniques to bolster output.

Chevron uses steam injection EOR for 80% of the Duri field, one of the largest steamflood projects in the world. Chevron announced plans to double oil production at the Minas field through the use of EOR to 140,000 bbl/d by 2014.

In addition to the Sumatra B a s i n , I n d o n e s i a p ro d u c e s significant quantities of oil from the East Java Basin with a joint operating agreement between Pertamina and PetroChina. This venture produced approximately 43,000 bbl/d at the end of 2011, and both companies announced plans to raise production by up to 10,000 bbl/d in the next few years.

Pertamina now faces the combined challenges of stemming oil production declines and meeting domestic demand. Much of the reserves remaining under Pertamina's c o n t ro l re q u i re E O R t e c h niques, currently beyond the technological capacity of domestic firms, or the development of basic infrastructure in remote areas of the country (mainly in the east). Partly because of an uncertain regulatory atmosphere and government measures to support local companies, foreign inVisit our website at www.safan.com

vestment in extracting these reserves remains limited. In addition, Indonesia's domestic operations have been limited by disputes with IOCs operating within Indonesia.

The 2001 discovery of the Cepu Block in East Java has the potential to counteract some o f I n d o n e s i a ' s p ro d u c t i o n decline. Estimated to contain 600 million barrels of recoverable reserves, this block contains three significant fields - Banyu Urip, Jambaran, and Cendana. After signing a PSC with Pertamina in 2005, ExxonMobil announced a new oil discovery at an exploration well in the Cepu block in August 2011. ExxonMobil operates the Cepu PSC with 45% interest in a joint venture with Pertamina's Exploration and Development (E&P) unit (45% interest) and four local government companies (combined 10% interest). The partners estimate that Cepu contains 600 million barrels of recoverable liquids and will have a peak production of 165,000 bbl/d. The project has encountered several delays in the development process.

Most notably, post-2011 development was hampered by land acquisition and permit obstacles, while SKK Migas declined to extend the work permit of ExxonMobil's head Indonesia executive. Banyu U r i p i s c u r re n t l y t h e o n l y producing field in the Cepu PSC and had reached a pro-

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duction level of about 26,000 bbl/d, as of April 2013. SKK Migas expects Cepu to reach full capacity of 165,000 bbl/d by the first quarter of 2015.

Deepwater exploration and production activity is focused in the Kutei Basin (off the coast of Kalimantan), Western Papua, and the Bonaparte Basin (adjacent to Australia in the Arafura Sea).

Chevron, Eni, Niko Resources, Statoil, Total, and Hess are the firms most active in Indonesia's deepwater field development. Chevron is the largest operator in these areas, managing five of the eight deepwater fields currently in development. Currently, technical and commercial success rates have not incentivized further development in deepwater areas.

A g i n g i n f r a s t ru c t u re a n d fields suggest that in the short term, the country will continue to struggle to meet production targets. Future oil

extraction will depend on the ability of the country to attract investment for exploration and production, particularly in deepwater offshore and frontier areas and in any technically challenging plays.

To this end, in 2012 Indonesia's Ministry of Energy and Mineral Resources asked the country's Ministry of Finance to lift land and building taxes on deepwater oil and gas exploration as a means of increasing future supply.

SKK Migas and the Indonesian government introduced policies aimed at creating investment incentives and improving the flexibility of the PSC bidding process. In particular, the government has pursued EOR and Technical Assistance Contracts (TACs) as part of Indonesia's push to raise crude oil production to 1 million bbl/d. To stimulate development in areas with poor infrastructure, the government has begun to grant PSCs that offer 15% to 20% of revenue to investors.

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We s t e r n m a r k e t a n a l y s t s still consider the upstream investment environment to be risky, and licensing rounds f ro m t h e p a s t t h re e y e a r s have been disappointing. The government only managed to award 21 of the 43 blocks offered in 2009, 10 of the 36 blocks offered in 2011, and 24 of the 42 blocks offered in 2012. As part of one round in 2012, the government awarded exploration rights to 14 out of 16 offered blocks, mostly as a result of uncontested bids.

The 2013 bidding round involves 18 oil and gas blocks, mostly contained in the underexplored eastern part of the country.

Under current regulation, local governments retain 15% of net revenues from oil and 30% of net revenues from gas produced within their jurisdiction. Domestic Market Obligations (DMOs) require

that a minimum of 25% of oil production be made available to the Indonesian market. In 2011, Indonesia's central bank mandated that foreign and domestic upstream enterprises must pass revenues through local banks, a significant shift for IOCs that created another hurdle for foreign investors.

Natural Gas

Indonesia possessed 104.4 t r i l l i o n c u b i c f e e t ( Tc f ) o f proven natural gas reserves in 2014, down from 108.4 Tcf in 2013, according to sources.

The country ranks as the 13th largest holder of proven natural gas reserves in the world, and the second-largest in the Asia-Pacific region, after China. The country continues to be a major exporter of pipeline and liquefied natural gas (LNG). At the same time, domestic demand for natural gas has doubled since 2005.

Natural gas shortages caused

by production problems and rising consumption forced Indonesia to buy spot cargoes of LNG to meet export obligations in recent years. The government began constructing new LNG receiving terminals and gas transmission pipelines to address domestic gas needs, although this is likely to reduce the natural gas available for export.

T h e re g u l a t o r y s t ru c t u re that shapes Indonesia's upstream oil sector also forms the basis for the natural gas sector. Pertamina accounted for 13% of natural gas production in 2012 through subsidiary Pertamina Gas, according to PricewaterhouseCoopers. IOCs such as Total, Inpex, ConocoPhillips, and ExxonMobil dominate the upstream gas sector.

To t a l a n d C o n o c o P h i l l i p s produced nearly 50% of dry natural gas in the country i n 2 0 1 0 , a c c o rd i n g t o P F C Energy. Other upstream investors in Indonesia's gas sector include various Chinese national oil companies, smaller international oil and gas companies, and local Indonesian energy firms, while the state-owned utility Perusahaan Gas Negara (PGN) carries out natural gas transmission and distribution activities.

Pursuant to a Domestic Market Obligation (DMO) stipulated in Indonesia's gov-

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ernment regulations, 25% of natural gas produced from production-sharing contracts in Indonesia must supply the domestic market. The government has imposed larger obligations in recent specific contracts. For example, the planned Donggi-Senoro LNG plans received government approval only after the developers designated 30% of the output explicitly for domestic consumption. Similarly, Inpex designated a third of the output from the planned Abadi floating LNG liquefaction terminal for the domestic market, according to the government.

EIA estimates Indonesia produced 2.6 Tcf of dry natural gas in 2012, mostly from offshore fields not associated with oil production. In recent years, companies have shifted attention to newer, underexplored offshore areas, particularly in the eastern regions of the country. Production grew at an annual rate of about 4% from 2002 to 2010.

In 2011 and 2012, production fell by roughly 5% compared to the previous years. Despite the decrease in production, Indonesia's 2012 gas production was the tenth-highest in the world.

Indonesia's largest fields are located in the Aceh region of South Sumatra and East Kalimantan. The Mahakam block, offshore East Kalimant a n a n d o p e r a t e d b y To t a l

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since 1970, currently accounts for roughly one-fifth of Indonesia's dry natural gas production. There is uncertainty over whether Indonesia plans to extend the PSC after the contract expires in 2017, and Total has reduced some development and production in the block since 2012. Chevron is developing several deepwater fields offshore East Kalimantan which are expected to produce a maximum of 1.1 Bcf per day (400 Bcf/y) of natural gas and 55,000 bbl/d of liquid condensates and begin operations in 2015.

In recent years, some companies have shifted their attention toward less-explored parts of the country. Pertamina, PetroChina, and ConocoPhillips are key producers in the Natuna Basin within the South China Sea. The companies produced about 200 Bcf of gas from the basin in 2011. As of the beginning of 2014, the partners have not reached a finalized PSC for the Natuna D Alpha block in the eastern section of the basin. The block is technically challenging to develop as a result of its large carbon dioxide concentrations, but it contains a sizeable 46 Tcf of proven reserves. For several years, Indonesia has faced military disputes with China over competing claims to the waters off Natuna Island, located in the northern region of Indonesia. China claims some

area around Natuna, as part of its 'nine dash line', which overlaps with Indonesia's exclusive economic zone. These territorial disputes could further delay exploration and development of gas resources around eastern Natuna.

The Bintuni Bay, located in West Papua, and the Central Sulawesi region are emerging a s n e w i m p o r t a n t o ff s h o re gas resource areas. In the area near West Papua, BP oversees proven reserves of 14.4 Tcf. Finally, the Arafura Sea in eastern Indonesia is mostly underexplored and contains the Abadi gas field, estimated to have reserves between 10 and 14 Tcf. Increasing domestic dem a n d c o n t i n u e s t o re d u c e Indonesia's capacity for exports, and the country might not be able to meet its external obligations. Moreover, Indonesia's geography presents a challenge to resource development and makes the switch to natural gas for dom e s t i c c o n s u m p t i o n m o re difficult. The nation's most prolific blocks of gas reserves are located far from its major demand markets, and regulatory uncertainty delays investment needed for exploration. Foreign upstream investment in PSC areas fell in 2012. ExxonMobil and Statoil relinquished deepwater blocks in 2013 after failing to discover economically viable Visit our website at www.safan.com

reserves, a trend that SKK Migas expects to continue.

Indonesia's government promotes exploration of coal bed methane and shale gas, alongside conventional crude oil and natural gas projects.

The Ministry of Energy and Mineral Resources estimates that the country has CBM reserves of 453 Tcf based on preliminary studies. In 2007, the Indonesian government started awarding CBM blocks in the South and Central Sumatra basins on Sumatra Island and the Kutei and Barito basins in East Kalimantan.

Singapore-based Dart Energy and Indonesian PT Energi Pas i r H i t a m b e g a n C B M e xploration activities in East Kalimantan in 2013, with the goal of supplying both power plants and the Bontang LNG facility. The government anticipates CBM production to reach 183 Bcf/y by 2020.

There is currently no shale g a s p ro d u c t i o n i n I n d o n e s i a , b u t p o l i c y m a k e r s a re interested in exploring the country's shale oil and shale gas potential. In April 2012, the Indonesian government initiated four shale gas study projects and expects commercial shale gas production to begin by 2018. As of December 2013, Indonesia has awarded only two shale gas PSCs for the Sumbagut block in North Sumatra, both to Pertamina. The Sumbagut block

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is estimated to contain about 19 Tcf of potential shale gas resources. EIA estimates that Indonesia possesses 46 Tcf of total recoverable shale gas resources. A major challenge to the growth of the shale industry is the cost of exploration in Indonesia, estimated to be as much as four times the drilling cost in North America because the deposits are far from demand centers and infrastructure needed to transport the gas.

All in, Indonesia’s energy output, and independence, is very much in the balance as shifting E&P parameters and government policies mean that Indonesia has to adapt quickly to the changes or risk its production-consumption differential growing even more. It is clear that Indonesia will have to explore unconventional sources and ramp up its deepwater activities if it is to stand a chance of reducing its energy deficit. The key to this is proper governance and adoption of new technologies and the country will have to relax its rigid structure to start achieving this.

References

Asia Pacific Economic Cooperation Badan Pusat Statistik (Center for Statistics), Government of Indonesia Bloomberg BMI Asia Pacific Oil and Gas Insights

BP Chevron ConocoPhillips Economic Research Institute for ASEAN and East Asia Energy Intelligence Group FACTS Global Energy Financial Times IHS EDIN IHS Global Insight Indonesia Ministry of Energy and Mineral Resources International Energy Agency Lloyd's List Intelligence National Oceanic and Atmospheric Administration NewsBase Asia Oil and Gas Monitor Patersons Indonesia Coal Review Petroleum Economist Platts Energy Economist PT PLN PwC – Mining in Indonesia PwC – Oil and Gas in Indonesia Reuters Rigzone The Jakarta Globe The Jakarta Post The New York Times Wall Street Journal Asia PET World Gas Intelligence

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Old Dog Learns New Tricks Oil and gas E&P started onshore and after decades of production is currently more often than not seen as a shrinking source. New frontiers such as deepwater and FLNG have opened up as sources for hydrocarbons, thus marginalising onshore E&P. However, onshore E&P still has an important role to play in the never-ending drive for energy sources.

W

R e p o r t Onshore Feature CIA 2005

ith all the talk being about deepwater developments and unconventional resources it would seem that onshore E&P is slowly being phased out.

on oil prices of $98 Brent and $89 WTI and U.S. natural gas prices of $3.66. These projections suggest their early look at 2013 spending levels likely underestimates total spending given current commodity price levels.

Oil and gas companies will spend about $723 billion on exploration and production (E&P) in 2014, an increase of 6.1 percent from 2013, Barclays Bank said in a report. The main areas driving spending growth are the Middle East, up 14%; Latin America, up 13%; and Russia, up 11%, according to the survey.

While it is easy to assume that the increase in expenditure is due to the more expensive activity in the deepwater and arctic sectors, it is critical to note that the biggest area of increased expenditure projected is the Middle East, which is not so much known for its offshore activity.

Global E&P spending is poised to reach a new record of $723 billion in 2014, up 6.1% from $682bn in 2013. 2014 should mark an acceleration of growth in North America to over 7% (led by the U.S.) coupled with continued solid growth (+6%) in international markets, particularly in the Middle East, Latin America, and Russia. Barclays estimate capital budgets in the U.S. and Canada will rise 8.5% and 3%, respectively, up from 4% and -2% in 2014. Companies are basing 2013 spending plans

More Onshore Drilling?

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by an increasing volume and complexity of well requirements in order to meet global production targets although meeting this growth may be a challenge. A significant number of high specification rigs and associated equipment will need to come to the market in the next five years and the pressure on the supply chain will be significant�.

One of the clearest indicators of increased E&P activity is rig demand. Perhaps surprisingly to some, onshore rig demand remains healthy.

Douglas-Westwood estimates that growth in global active rig demand will average 5% per annum over the 2012-2016 period. This latest insight from Douglas-Westwood suggests an increasingly important role for frontier markets globally with an estimated two thirds of active rig demand coming from regions outside North America by 2016.

C a l u m S h a w, l e a d a u t h o r o f t h e D o u g l a s - We s t w o o d l a n d d r i l l i n g re p o r t c o m mented that, "The world onshore drilling rig market is set to expand from an estimated 9,700 rigs today to more than 11,000 units by 2016. Such growth is driven

While countries such as Kazakhstan, Mexico and Oman are likely to witness decline, other markets including China, Colombia, Russia, Saudi Arabia, Iraq and the USA are all expected to see an increase in the number of rigs required.

Follow-on investments in new-

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build rig construction and the updating of current fleets which have experienced underinvestment over the last three decades.

Saudi Arabia has about 98 onshore rigs currently drilling for oil and natural gas, according to Shoaibi Group, a service company used by the kingdom’s state-run producer.

Shoaibi, based in Khobar in Saudi Arabia, published the figure in an e-mailed statement while announcing a joint venture with U.K. rig engineeri n g c o m p a n y L a m p re l l P l c .

(LAM) Shoaibi didn’t provide comparison figures for earlier dates and state- run Saudi Arabian Oil Co. doesn’t publish information on how many rigs it has in operation.

“Saudi Arabia has an estimated 98 onshore drilling rigs in place and there is a rising demand for advanced drilling equipment and oilfield services in the upstream market, which justifies Lamprell’s expansion into the market at this time,” Shoaibi Group Director Khalid al-Shoaibi said in the statement.

The service company’s estimate compares with a figure of 121 rigs that Saudi Arabia used for both onshore and offshore work in 2011, and 98 in 2010, according to OPEC’s annual sta-

Onshore Feature

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tistical bulletin from July. The country boosted production this year and pumped an average 9.8 million barrels of crude a day during the first eight months of 2012, compared with an average 9.2 million a day during all of last year, according to data compiled by Bloomberg.

While most Saudi Arabian rigs operate on land, it also has some off its coast in the Persian Gulf and in an offshore partitioned zone where it shares oil and gas output with Kuwait.

Saudi Aramco, as the state oil company is known, plans to increase its oil and gas drilling-rig count by 12 percent this year to 145 to boost natural-gas production from new fields and oil output from its Manifa field, Sadad al-Husseini, a former executive of the state-run company and an independent energy consultant, said in December.

Increased Well Activity

While Barclays’ expectation for 2014 suggests a modest deceleration in global spending growth, they believe the mix of spending is poised to shift away from large infrastructure projects towards greater drilling, evaluation and completion activity, implying a stronger underlying revenue opportunity for the group and the diversified oil service companies in particular.

The energy business research and consulting firm DouglasWe s t w o o d L t d . c o n c l u d e d through a recent, major research

program that, from 2014-2020, the international oil and natural gas industry will need to drill more than 670,000 wells in order to meet demand forecasts, the firm said Feb. 26.

The firm’s World Development Drilling & Production Forecast states that by 2020, global oil and natural gas demand will have increased 17% from 2013, noting that in 2020, the number of wells will have to exceed 106,000, but in 2013 the number of wells was more than 79,000.

“As the easiest-to-access oil and gas reserves deplete, each year we have to drill more and more wells for less and less production per well. Over the period, numbers of development wells drilled need to grow 35% to enable oil and gas production to meet an expected demand growth of 17%,” said chairman John Westwood.

He added, “This effect is most marked onshore where by 2020 we expect production to grow by 15%, whereas offshore production should grow at 21% due to developments in deepwater.”

Matt Loffman, a senior analyst for Douglas-Westwood, noted that the U.S. has made gains in oil and natural gas production over the last two years, adding that “as rigs are focused on oil-targeted wells in the future, onshore oil well completions are set for a 36% increase by 2020.”

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The Forecast noted that “traditionally productive regions are in decline and face a variety of futures,” but also noted that onshore activity will dominate the future, “accounting for 97% of well completions and 71% of global output.”

D o u g l a s - We s t w o o d L t d . , based in Faversham, Kent, U.K., provides market research and consulting to the international energy sector.

Matt Cook, of Douglas-Westwood London, comments, “It is widely agreed that the age of so-called ‘easy oil’ is over as onshore and shallow-water fields deplete – indeed, it seems that the production of the international oil majors such as BP, Exxon, Shell, Statoil, Total, and others has already peaked.

However, some Middle Eastern national oil companies (NOCs) may also be running out of ‘easy oil.’

“Our data for Kuwait, Qatar, Saudi Arabia, and the United Arab Emirates shows that, between 2000-2013, their production grew by 33%, but well numbers by 109% – they are drilling more and more wells for less and less oil,” Cook notes.

“Furthermore,” he says, “results from our new Global Drilling & Production Forecast model indicates that, in order to meet their target production, these countries will need to increase wells drilled from 1,156 in 2013 to 1,558 in 2020,

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a rise of 35%. Saudi Arabia, for one, needs to access its onshore gas reserves in order to meet growth in its own growing energy consumption that threatens to overwhelm its oil export capability – yet more wells!

tion, which was up significantly. Directional Drilling, MWD/ LWD, Artificial Lift, Intelligent Well Completions, and Drill Bit Technology were also frequently mentioned as important technologies used in the oilfield.

“If this is indeed the shape of things to come,” Cook concludes, “it bodes well for drillers and oilfield service companies at a time when the IOCs are seeking to limit their spend on highCAPEX projects.”

A focus on unconventionals in some areas could result in a greater demand for higher-specification rigs.

What all this means is that despite there being a dwindling number of new onshore discoveries the activity level is set to go up. Although offshore production growth is set to be higher, onshore production is still growing (21% offshore to 15% onshore).

Unconventional – More than Just Offshore

Shale gas, CBM and EOR are three factors that have, in my opinion, kept he flag flying for onshore E&P. These three areas of E&P have resulted in increased onshore activity and increased demand for rigs.

For the sixth consecutive year, Fracturing/Stimulation and Horizontal Drilling were most commonly cited among operators as having the greatest impact on their spending plans. 3D/4D Seismic fell, which is not surprising given recent shift away from exploration spending and towards Reservoir Recovery Optimiza-

Demand for land drilling rigs is expected to increase 23% by 2017 with the greatest percentage of growth expected in Western Europe, according to a forecast released recently by Douglas-Westwood.

Although the region has a small number of rigs compared t o o t h e r a re a s , a n t i c i p a t e d unconventional action could spark a 63% increase in drilling rigs within the next five years.

Currently, the Western European region has an estimated 115 capable drilling rigs, according to the report. Pushing the number higher is expected focus on shale reserves within the UK region.

Onshore shale gas basins in Western Europe are believed to hold 10.5 Tcm (72 Tcf) of technically recoverable resources, according to the US Energy Information Administration. About half of this amount is in France’s Paris and Southeast basins.

“With many fields in the traditional producing regions of the world reaching maturity, Visit our website at www.safan.com

unconventionals will account for an increasing proportion of future hydrocarbon production,” Hannah Lewendon, the report’s author, said in a prepared statement. “Deviated and horizontal drilling is likely to increase as a result of this, driving demand for higher specification rigs that are capable of such complex techniques.”

The report showed that deviated and horizontal wells currently represent 28% of the development wells worldwide. Around 31% of total wells are predicted to be nonvertical by 2017.

Overall, “the global fleet will need to increase by approximately 1,303 capable units to meet drilling demand,” according to the report. “Strong volume growth in North American, Asian, Eastern European, and former Soviet Union (FSU) markets is expected to drive the increase, although all other regions can expect to see increases in their fleet size through 2017.”

Demand drivers include higher global production targets and the increasing complexity of well requirements as well as exploration in new regions and EOR in mature regions, the report said.

Rigs drilled onshore are forecast to increase 20% by 2017.

The uptick in activity is unlike what the industry experienced in the previous five-year period, when an economic downturn resulted in a 3% drop in wells drilled. In North Amer-

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ica the number of rigs drilled decreased 28% from 2008 to 2009, according to the report.

In the next five years, however, North America’s capacity of 3,487 capable drilling rigs is predicted to increase by 11% as operators continue developing shale resources with activity nowadays focused more on oil than gas.

“Growth in oil demand from advancing economies is expected to continue, and markets formerly inaccessible to western drilling contractors are allowing greater access,” Lewendon said.

“Although the activity of international rig contractors is growing in some countries, markets with high rig counts including China, India,and Venezuela remain dominated by national oil companies’ operations.”

Asia, which has an estimated 2,065 capable drilling rigs, could see a 13% increase within five years. Australasia, where the report said most rigs are designed for drilling at shallow depths, could experience a 22% increase.

The region currently has about 364 capable drilling rigs.

Latin America, which has an estimated 835 drilling rigs, could have an 11% percent increase, according to the report.

National oil companies also continue to dominate the majority of markets within the Middle East and North Africa region, but growing international contractor

participation in the significant rig fleets of Iraq and Kuwait is likely to continue throughout the forecast period.

The report showed the FSU and Eastern European regions combined have an estimated 2,073 capable drilling rigs.

That amount could grow by 15% by 2017.

“Despite the forecast growth, challenges remain including the political instability in the Middle East,” Lewendon said.

“However, increasing difficulties here will only serve to shift drilling activities to more stable countries.”

The Middle East and North Africa regions, where “highly productive wells are invariably drilled by modern rig fleets in major markets including Saudi Arabia and Algeria,” has just more than 1,000 drilling rigs. This amount could grow 6% by 2017.

Security also is of concern in Sub-Saharan Africa, the report noted. Despite the concerns, which also include rig mobility issues, the number of drilling rigs is predicted to jump by 38%. The region currently has 124 rigs.

Douglas-Westwood called the outlook for growth “positive,” but pointed out obstacles. Maturing fields and new hydrocarbon resources will increase the demand for rigs capable of deviated drilling, the report Visit our website at www.safan.com

said. “As [EOR] and fracturing techniques become more in demand, greater investment and addressing of environmental concerns will need to take place as the industry seeks to increase output from previously inaccessible reserves.”

The Future

The oil and gas industry has survived and thrived over the years simply because of one main reason – demand for hydrocarbons as an energy source.

However, the industry is volatile and reactive. Who can forget the

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death knolls being sounded for onshore E&P growth at the turn of the decade? Yet the Macondo incident led Obama to promote onshore E&P and curb offshore E&P, delaying onshore activity being put off to pasture.

onshore there will be production! It might not be as large a growth market as offshore E&P, but that can change as quickly as a new technology can be developed.

Shale gas, oil sands, CBM and EOR in each turn came to light up the onshore E&P scene just when its lights were dimming. There will always be technological advancements to make it worth extracting oil and gas from land. As long as hydrocarbons can be found

Barclays Deloitte Petroleum Services Douglas-Westwood EIA Facts Global Energy Halliburton Hart Energy Newswire Reuters

References

PET

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Offshore Key to Future Growth With easy oil being a thing of days past and the oceans and the artic regions considered to be the last bastions of virgin resources for oil and gas it is clear that offshore E&P is sure to grow. This report states in summary some of the points in favour of this view.

A

R e p o r t Offshore E&P CIAReport 2005

s the world reaches new heights of industrialisation and advancement, the need for energy becomes more pressing. The extent to which the world can develop, and the corresponding thirst for energy, seems boundless. Unfortunately, the main source of energy currently, hydrocarbons, are non-renewable and far from limitless. Decades of using the finite resources of hydrocarbons available has led to depletion and thus widening the parameters of search for energy, which has resulted in increasingly more E&P offshore.

New annual onshore well numbers are set to grow 35% by 2020, as more completions are needed to offset ongoing production decline. Worldwide, more drilling for less oil & gas is a recurring theme; the Middle East will need to achieve more than 30% growth in drilling as the NOCs of KSA, Kuwait, Qatar and UAE start large redevelopments in the near-term – nevertheless, production will rise just 10% due to the maturing of existing fields. It is of note that the well numbers of the national oil companies will surge as the international oil majors endeavour to reign-in their spending.

Douglas-Westwood’s (DW) new Drilling & Production information service is producing some interesting numbers, not least that meeting future global oil & gas demand will require massive numbers of new development wells to be drilled; in 2014 some 83,000, of which 80,000 will be onshore and 3,000 offshore. However, a forecast 17% increase in oil & gas demand by 2020 means that annual well completions will need to climb 35%; in all an additional 670,000 wells must be drilled by the end of the decade.

However the number is smaller offshore. Offshore, the developing shallow water gas and highly productive deepwater sectors will offset the effects of an aging shallow water oil sector into the forecast, with total offshore oil & gas production set to rise 22% by 2020. DW expects to see a surge of deepwater well completions in the medium term - reaching 476 by 2018, up from 185 in 2013.

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Greenfield projects (onshore and offshore) in Russia could see production maintained at

current levels into the 2020s, though recent diplomatic tensions could affect this considerably. China will invest significantly into output at home and abroad, notably Central Asia, as it looks to satisfy rapidly rising domestic demand.

On a global basis, much of the drilling is due to the continued resurgence of the dominant North American market (which accounted for 62% of worldwide development wells drilled in 2013).

Floating Production

Douglas-Westwood’s World Floating Production Market Report forecasts that between 2014 and 2018 $99 billion (bn) will be spent on floating production systems (FPS) – an increase of 138% over the preceding fiveyear period.

Report author, Damilola Odufuwa, commented, “FPSOs will form the largest segment of the market (80%) both in terms of units installed and forecast capital expenditure (Capex) over the 2014-2018 period. Latin America accounts for 29% of the 139 installations forecast and 38%of the projected Capex.

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“The FPS sector recovery following the 2008/2009 downturn continues steadily. A total of 54 units were ordered in 2011-2013 compared to 23 units during 2008-2009. There has been little growth in the annual value of installed units over the last four years; however, 2014 is expected to show a significant increase in the value of units deployed.

“The strong forecast growth is despite the industry still coming to terms with a number of demand-side and supply-side issues. The failure of Brazilian operator OGX in 2013 and the slow-down in overall upstream expenditure in 2014 will impact the market in the near-term.

Likewise the industry’s record in terms of project execution has been poor, with most projects delivered late and significantly over-budget. Some industry players are now suggesting a new approach is required.

“However, the long-term growth in the sector is underpinned by the continued exploitation of deep waters, marginal fields and fast-track/short term deployments. Deepwater FPS deployments are expected to total $68bn and account for over two-thirds of the total spend.”

Deepwater

Deepwater expenditure is expected to increase by 130%, compared to the preceding five-year period, totalling $260 billion (bn) from 2014 to 2018, with growth driven primarily by Africa and

the Americas. As production from mature basins onshore and in shallow water declines, development of deepwater reserves has become increasingly vital. Robust oil prices support investment in deepwater developments – the sustained high oil prices over the past few years have increased confidence in the sector.

Douglas-Westwood’s World Deepwater Market Forecast’s report author, Balwinder Rangi, comments, “Africa and the Americas continue to dominate deepwater capital expenditure (Capex), with $213bn set to be spent over the next five years.

Africa is forecast to experience the greatest growth among the three regions, as East African natural gas developments begin production and become more prominent in the latter years of the forecast period. Latin America will remain the largest market and North America is expected to experience the least growth. “ D o u g l a s - We s t w o o d h a s identified a temporary trough in global expenditure in 2015 primarily driven by delays to delivery of FPS units in Latin America. African projects have also experienced delays resulting in a surge in Capex from 2016 onwards.”

Steve Robertson, report editor, concludes, “The deepwater market requires significant continued investment in infrastructure. Whilst the economic feasibility of deepwater fields

varies, typically oil prices of $80 per barrel (WTI) over the longterm ensure the viability of the majority of developments. However, despite robust oil prices, a number of flagship projects have been cancelled through surging E&P costs. Challenges in project execution, cost and local content are not unique to deepwater.

Ultimately, the maturity of onshore and shallow producing areas is driving increased and unprecedented levels of activity in deepwater.”

Subsea

Since publishing their pioneering “Gamechanger” study on the subject back in 2003, Douglas-Westwood have tracked the emerging subsea processing (SSP) sector with anticipation of increased operator participation and spend.

SSP technology has since been applied to many fields including Total’s Pazflor where gas/liquid separation and boosting equipment were implemented in 2011. Subsea boosting is a widely accepted technology and separation t e c h n o l o g y i s i n c re a s i n g l y used by operators – Shell’s Perdido field utilises the first ever full subsea separation system.

There have also been recent increases in the development of compression technology, predominantly by Statoil. The operator’s pioneering Asgard and Gullfaks subsea gas compression projects are in their latter stages of development and both manufacturer Aker Solumarch/april 2014

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Offshore E&P Report

tions and the wider offshore industry wait in eager anticipation of proof of concept for the huge compression units. Could this provide the incentive required to push compression and other SSP technologies into even more widespread use?

world. Particular focus was placed offshore Norway, but also Brazil, the Gulf of Mexico and West Africa which dominate global deepwater activity and where SSP has potential to play a significant role in the future developments.

Conducted in 2012, DW’s Subsea Joint Industry Study found that while SSP was still in the early stages of implementation, SSP technologies were being considered by all 30+ surveyed operators throughout most regions of the

As the increased theme of IOC capital discipline currently plays out, operators will remain risk averse; however, the search for solutions that may reduce offshore project costs should lead to further active consideration of SSP technology.

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Implications

As always with the oil and gas industry, there is always the need for technological a n d o p e r a t i o n a l i m p ro v e m e n t s i n o rd e r t o e x p l o re new territory. Increasingly more R&D and investment is moving towards building and operating high-spec offshore rigs, developing new subsea technologies and operating in harsh environments (like deepwater). This bodes well for regional companies dealPET ing in these sectors.

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Bids & Pieces to take the Hakuyru-11 rig following the drilling of the Balqis-1 and Boni-1 wells.

The Gobi-1 exploration well, located in the Gurita PSC Republic of Indonesia, will now be drilled in the fourth quarter of 2014.

SOUTHEAST ASIA

R e p o r t Project News CIA 2005

INDONESIA Lundin Petroleum Completes Well in Natuna Sea In mid-March Lundin Petroleum AB (Lundin Petroleum) announced that the exploration drilling of the Boni prospect in the Baronang PSC, Natuna Sea, Indonesia has been completed.

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On 11th March 2014 drilling of the Boni-1 well reached Total Depth at 2,214 metres below mean sea level in the granitic basement as per the drilling programme. Preliminary analysis of LWD logs indicates that the well encountered the targeted Oligocene Lower Gabus Formation sandstone in well-developed reservoirs but no hydrocarbons were encountered.

Lundin Petroleum, through its wholly owned subsidiary Lundin Baronang BV, is the operator and has an 85 percent working interest in the Baronang PSC. Partner Nido Petroleum Limited has a 15 percent working interest, where the recent 5 percent increase remains subject to governmental approval. Lundin operates five PSCs in Indonesia, namely Baronang, Cakalang, Gurita, South Sokang and Cendrawasih VII. First Gas from Peluang Project Ahead of Schedule Santos on 25 May announced that natural gas production has commenced ahead of schedule and on budget from the Peluang gas project offshore East Java in Indonesia.

The Boni-1 side-track will be permanently plugged and abandoned in conjunction with Balqis-1.

Sanctioned in February 2013, Peluang is a tie-back to the existing facilities at the Maleo gas field and is located in the Madura Offshore Production Sharing Contract (PSC).

Rig contract owner Premier Oil has exercised its option

The project is expected to have gross peak production of Visit our website at www.safan.com

ried out by the consortium of Shell Malaysia (35%), Conoco Phillips (35%) and PETRONAS Carigali Sdn Bhd (30%).

25 million standard cubic feet per day.

Santos Vice President Asia, WA&NT John Anderson said Peluang first production represented the delivery of another project into the company’s expanding Asian portfolio.

“Peluang is the fourth operated asset for Santos in South East Asia. The success of first gas ahead of schedule and on budget with Peluang represents another significant milestone in the company’s delivery of a strong growth strategy in Asia,” he said.

“In addition to Peluang, Santos is also focused on progressing our recently acquired position in the Ande Ande Lumut oil field in the West Natuna Basin.”

S a n t o s P re s i d e n t I n d o n e s i a M a r j o l i j n Wa j o n g s a i d Peluang gas will be used by domestic consumers in East Java, Indonesia, as is the case with other gas produced by Santos in East Java.

“We already have gas production from the Oyong, Wortel and Maleo fields in offshore East Java, so this builds on our capacity in the region. Peluang also demonstrates our ability to deliver new projects in Indonesia,” she said.

Santos has a 67.5% interest and is the operator of the Madura Offshore PSC. Other partners are PC Madura Ltd and PT Petrogas Pantai Madura.

MALAYSIA PETRONAS and Shell Announce Limbayong Oil Discovery On the 17th of March PETRONAS and Shell were pleased to announce an oil discovery offshore Sabah.

The discovery was made via the Limbayong-2 well during the appraisal of the Limbayong gas field by Shell. The appraisal well encountered 136 metres of oil bearing sands, and there are plans to conduct more appraisal work on the discovery to determine its recoverable volume.

PETRONAS’ Executive Vice President of Exploration and Production Dato’ Wee Yiaw Hin said: “We are indeed pleased with the discovery which affirms the hydrocarbon prospects of Malaysia’s deep water areas.”

Iain Lo, Chairman of Shell Malaysia and Managing Director of Sabah Shell Petroleum Company Ltd said: “This discovery attests to the significant potential in this area and is a positive development for exploration activities in East Malaysia.”

The drilling of the Limbayong-2 appraisal well was car-

Fugro Awarded Three Year Contract by Murphy Sabah Oil In late March it was announced that Fugro has been awarded a contract for three years, plus a one year extension option, by Murphy Sabah Oil Co., Ltd. for the provision of rig and subsea positioning services.

The award will further strengthen a decade-long working relationship in support of Murphy’s deepwater drilling and development programs offshore Sabah and Sarawak, Malaysia. Support services include the use of highly specialised subsea survey systems for accurate metrology measurements, along with the provision of accurate offshore surface and subsea positioning and navigation systems for Murphy’s drilling units and vessels, working in water depths of up to 2,000m.

The contract award supports Fugro’s commitment to the continued development of Malaysian resources and further investment into Fugro’s activities in Malaysia.

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Keppel Secures Contracts worth US$140 Million Keppel Offshore & Marine Ltd's (Keppel O&M) subsidiaries Keppel Shipyard Ltd ( K e p p e l S h i p y a rd ) , K e p p e l Singmarine Pte Ltd (Keppel Singmarine), and Keppel Nantong Shipyard Co. Ltd (Keppel Nantong) have secured contracts worth a total of about S$140 million,it was revealed in March.

Mr Michael Chia, Managing Director (Marine & Technology) of Keppel O&M, said, "We are happy to be able to offer our comprehensive suite of offshore and marine solutions to our valued repeat customers, who are once again placing their confidence in Keppel by entrusting their projects with us. " K e p p e l S h i p y a rd ' s l a t e s t contract bears testament to our expertise and experience in Floating Production Storage and Offloading (FPSO) turret fabrication and installation, while Keppel Singmarine's and Keppel Nantong's contracts reiterate our competency in the construction of a variety of ships, including ice-class vessels."

Keppel Shipyard will undertake for SOFEC, Inc. (SOFEC) the fabrication of an external turret mooring system for an FPSO vessel that will operate in the Tweneboa-EnyenraNtomme fields in Ghana, in water depth averaging 1,500 metres. Fabrication of the turret is expected to be completed in 1Q 2015.

Project News

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The modules will be transported from Aibel’s yard in Laem Chabang to Singapore where they will be integrated on a FPSO. The end client is Tullow Ghana Ltd. The FPSO will operate in deep waters off Ghana, West Africa.

THAILAND First Steel Cut in the Modec TEN Project The start-up of a new important project was celebrated in Thailand this week in mid-March.

Managing Director Jim Ryan at Aibel Thailand explains that the celebration was held at subcontractor Deeline’s fabrication shop. It started with a traditional worship followed by a Buddhist monk blessing ceremony. The monks blessed the steel, machinery, visitors and staff “At exactly 9.19am Modec's Jeff Knox activated a plate cutting machine that cut the first steel plate in the project. This ceremony was followed by guest speeches,” he says.

The contract for the topside procurement and fabrication of the Tweneboa, Enyenra and Ntomme (TEN) project with Modec was signed in February. Aibel Thailand is delivering seven modules with a weight of 9,400 tons to the FPSO. “We are pleased to continue our good relationship with MODEC. Aibel has also successfully delivered modules in the projects Tupi, Guara and OSX3,” Ryan explains.

VIETNAM Russia’s Lukoil Pulls out of Vietnam Exploration Project Russia’s largest private oil firm Lukoil has withdrawn from a joint venture exploration project in Vietnam following unsatisfactory results, an executive at the Vietnamese partner company told told reporters early this year..

L u k o i l ’ s s u b s i d i a r y, L u koil Overseas Vietnam B.V, bought a 50 percent stake in a project to develop the Hanoi Trough-02 (HT-02) oil field on the East Sea shelf in April 2011.

Do Van Hau, general director of PetroVietnam, the local partner, said it is normal for companies to withdraw in such circumstances.

The same day Lukoil p re s i d e n t Va g i t A l e k p e ro v confirmed the pullout to Russian news agency RIA Novosti but provided no further explanation.

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In May 2012 the company told investors in Hong Kong that Lukoil failed to find commercial reserves after drilling two wells off Vietnam.

Grigory Volchek, a spokesman for the company’s overseas unit, told Bloomberg that Lukoil was reconsidering its Vietnam project.

Vietsovpetro, a joint-venture between PetroVietnam and Russia’s Zarubezhneft, is currently the largest oil explorer in Vietnam.

Other Russian companies including Gazprom and Rosneft are expanding exploration in the Vietnamese continental shelf, it was reported.

The unit was named "PTSC Lam Son" at a ceremony held in Singapore last Saturday by PTSC and its partners, including Keppel shipyard. PTSC General Director Phan Thanh Tung said the project is entering its final phase and PTSC Lam Son is expected to set sail for Viet Nam at the end of this month.

Nguyen Hung Dung, Deputy General Director of the Viet Nam National Oil and Gas Group, said implementing this project has helped PTSC staff improve their management and operational skills for major projects, contributing to the group's efforts to ensure national energy security.

Husky Energy Delivers Production Husky Energy (TSX:HSE) and CNOOC Limited have commenced first production at the landmark Liwan Gas Project in the South China Sea. "Liwan is Husky's largest project to date and places us inside the door of one of the fastest growing energy markets in the world," said CEO Asim Ghosh. "It was a massive undertaking and is a great achievement for deepwater gas production in the Asia Pacific Region."

Located approximately 300

VN Firm Builds Floating Unit to Serve Oil Field The PetroVietnam Technical Services Corporation (PTSC) has successfully built a floating production, storage and offloading (FPSO) unit to serve the Thang Long-Dong Do field off the coast of Vietnam.

Owned by the Lam Son Joint Operation Company (LSJOC), the unit has been converted from an oil storage vessel at a total cost of over US$400 million. It is designed to store at least 350,000 oil barrels, process 18,000 barrels a day and operate non-stop for more than a decade.

This is the first time a Vietnamese contractor has done all phases of the conversion from capital raising, designing and repairs to operation and maintenance.

THE ORIENT

CHINA

kilometres southeast of the Hong Kong Special Administrative Region, the project consists of three fields: Liwan 3-1, Liuhua 34-2 and L i u h u a 2 9 - 1 , w h i c h s h a re a s u b s e a p ro d u c t i o n s y stem, subsea pipeline transportation and onshore gas processing infrastructure. march/april 2014

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The Liwan 3-1 field has started production, with initial natural gas sales expected to be approximately 250 million cubic feet per day (mmcf/ day) gross and increasing to approximately 300 mmcf/day in the second half of 2014. Initial sales of condensates and natural gas liquids from Liwan 3-1 are expected to be approximately 10,000 to 14,000 barrels of oil equivalent per day (boe/ day) gross.

The Liuhua 34-2 field will be tied into the Liwan infrastructure in the second half of 2014, subject to final approvals.

Production from the Liwan 3-1 field is scheduled to go offline for approximately six to eight weeks to provide for the tie-in of the field.

Following the tie in of Liuhua 34-2, combined gas sales are anticipated to increase to approximately 340 mmcf/day (gross). Natural gas from both fields will be processed at the onshore gas terminal at Gaolan and sold to the mainland China market, with initial gas production covered by fixed-price gas sales agreements.

Total gas sales are expected to rise towards a range of 400 to 500 mmcf/day (gross) with the planned tie-in of the Liuhua 29-1 field in the 20162017 timeframe.

Production from Liwan will contribute to the Company's growth this year as per overall guidance. The startup was achieved during one of the most

Project News

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extreme weather seasons in recent history in the South China Sea. Husky expects to achieve the lower end of its Asia Pacific production guidance of 35,000 to 45,000 boe/day.

& Marine Engineering (DSME) shipyard in Okpo, South Korea.

The facility, scheduled to be completed in Quarter 4 of 2015, will be the world’s first floating LNG facility in operation.

Husky holds a 49 percent interest in the Production Sharing Contract (PSC) for the Liwan Gas Project and operates the deepwater infrastructure. Its partner CNOOC Limited holds a 51 percent interest in the PSC and operates the shallow water facilities and onshore gas terminal. The first stage of the US$6.5 billion project connecting the Liwan 3-1 field and work to date to tie in the Liuhua 34-2 field have been completed on budget.

The launch, which took place on 5 April 2014, saw the 365-metre-long hull – equivalent to three NFL football fields in length float out at a dock and launched to anchor at a quayside of DSME shipyard where the facility is being constructed. This phase marks another milestone in the development of the facility and signifies the near-completion of hull construction works, less than 10 months since the cutting of the first steel in June 2013.

The Company continues to advance a rich portfolio of opportunities in the Asia Pacific Region, including shallow water gas developments offshore Indonesia and exploration prospects offshore Taiwan.

SOUTH KOREA PETRONAS Launches Hull of Its First Floating LNG Facility PETRONAS has launched the hull of its first floating liquefied natural gas (PFLNG 1) facility at the Daewoo Shipbuilding

PETRONAS’ Vice-President and Venture Director of LNG Projects (Domestic), Gas & Power Business Datuk Abdullah Karim said, “It is an impressive achievement that we launch the hull within a short time frame following the keel laying process that began on 6 January 2014.

In addition, the project has also achieved more than 5.5 million total safe man-hours since the project commenced in March 2012 with no occurrence of loss time incidents at the project site.”

“We look forward for the project team to continue driving this momentum further to achieve our committed milestones, in line with our plans and expectations. “PETRONAS is currently working closely with its strategic partners, Technip and Daewoo Shipbuilding & Marine Engineering to ensure that the project is delivered safeVisit our website at www.safan.com

ly, in accordance to project specification and quality, within cost and on schedule,” he added.

dent of Malaysia & Brunei Syed Feizal Syed Mohammad; PETRONAS’ Executive Vice-President, Upstream, Dato’ Wee Yiaw Hin; PETRONAS’ Vice-President of Technology & Engineering, Dr. Colin Wong Hee Huing, other senior executives from the respective companies and project team members.

Cambay-77H Operations Update Oilex Ltd provides the following information regarding the Cambay-77H well.

SOUTH ASIA

for the 9 5/8 inch casing. While pulling out of hole (POOH) to service a mud pump, the Essar Land Rig #4 (Rig) experienced mechanical issues and is currently on equipment downtime at no cost ($0.00 day rate) to the Cambay Joint Venture.

Drilling of the 12 ¼ inch hole section reached 1,626.5m MD which is approximately 26.5m above the planned casing point

The PFLNG1 vessel, also known as PFLNG SATU, will be moored in Malaysia’s Kanowit gas field, 180 kilometres offshore Sarawak and will produce 1.2 million tonnes of LNG per year. It will play a significant role in PETRONAS’ efforts to unlock the gas reserves in Malaysia's remote and stranded fields currently deemed uneconomical to develop and evacuate and will help meet the growing demand for gas.

The floating LNG facility is expected to change the landscape of the LNG business where the liquefaction, production, storage and offloading processes of LNG - previously only possible at onshore plants – will now be able to be carried out hundreds of kilometres away from land and closer to the offshore gas fields. The facility can also be the solution for early monetisation and more agile LNG production.

Present at the launch were PETRONAS’ President and Group CEO Tan Sri Dato’ Shamsul Azhar Abbas; DSME’s President & CEO Mr. Jaeho Ko; Technip’s Chairman & Senior Vice-Presi-

INDIA

Some of the required replacement parts have been ordered march/april 2014

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and are being airfreighted from Houston while others have been locally sourced. This reflects the fastest delivery option for special parts not normally included as onsite spares for drilling rigs. It is anticipated the Rig will be operational within 10 ‑ 12 days.

AUSTRALIA AWE Awarded New Exploration Permit Offshore Western Australia AWE Limited in mid-April announced that it has been awarded a new exploration permit offshore Western Australia, WA-497-P (formerly release area W13-18), as part of

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The permit covers an area of 560km2 in water depths ranging from 150m to 500m and is located in the Exmouth Subbasin of the North Carnarvon

Basin, immediately adjacent to the producing Pyrenees, Vi n c e n t a n d C o n i s t o n o i l fields and north of the Macedon Gas Field.

THE PACIFIC

Project News

the Australia 2013 Offshore Petroleum Exploration Acreage Release.

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AWE holds 100% equity in WA-497-P, a six year exploration permit, and will be the Operator. In the first year, AWE has committed to reprocess the existing permit-wide 3D seismic data using the same state-of-the-art technology that was successfully applied to upgrade the prospectivity in a number of AWE assets such as the Ande Ande Lumut, La Bella and Tui fields.

said that in an initial review of the permit area, AWE has identified a significant new play concept in addition to the proven plays in adjacent permits.

"Exploration permit WA-497-P contains a number of interesting prospects that complement AWE’s strength’s in sub-surface appraisal and early stage development," Tupper said.

"We have been steadily growing our base of quality exploration and early stage appraisal assets and we are now actively evaluating opportunities in Australia, New Zealand and Indonesia. These include the unconventional gas potential of the onshore Perth Basin, the La Bella gas field in the Otway Basin, oil and gas discoveries in the Natuna Sea and the East Java Sea, Indonesia, and an onshore permit in New Zealand that we secured last year.

"The North Carnarvon Basin features some significant producing projects and we are looking forward to evaluating the potential of exploration permit WA-497-P," he said.

PET

Have you read our other magazine?

see us on the web at http://www.safan.com

Neil Tupper, General Manager Exploration & Geoscience, Visit our website at www.safan.com

Scene & Heard Oil and Gas Production Target Over-Fulfilled In 2013

By the 24th hour of 31st December 2013, the production output of Vietnam National Oil and Gas Group (Petrovietnam) had reached 16.71 million tonnes of oil and 9.75 billion m3 of gas.

With the tireless efforts of the units, contractors and all officers and employees, after one year with the slogan "Highleveled Determination, Right Action, Good Solution, Early Finish", PetroVietnam has successfully completed the 16-million-ton target assigned by the Government at 16:20pm of 17th December 2013 with 14 days ahead, while exceeding the oil production output of 16.7 million tonnes that the Group committed to the Government. This is also the 5th consecutive year that PetroVietnam over-fulfilled the oil and gas exploration target ahead the schedule.

The over-fulfilment of 2013 oil and gas production target is a gift and delight to welcome 2014.

In the context of the country's economy difficulties due to the impact of the global economic crisis, the target over-fulfilment has significantly contributed to increasing revenues for the country and is also a source of spiritual encouragement, motivation for the petroleum workers who spend days and nights clinging to the sea to continue striving for

oil and gas production targets in 2014 and subsequent years.

lion m3 of gas assigned by the Government for 2014.

Looking back on the accomplishment of the year, it can be seen that with a spirit of solidarity, unity and consensus, PetroVietnam has overcome many difficulties and challenges, from the strict management of exploitation of each sea, each field to the determination to apply good solutions to operate and overfulfill the plan for the new wells, new mines, new projects such as Hai Su Trang on 19/5/2013, Hai Su Den on 19/06/2013, Tho Trang on 29/6/2013, Dorado on 20/11/2013, Pirana on 25/12/2013 (Block 67 - Peru) and especially Hai Thach – Moc Tinh gas mines – the national key projects operated since 06/9/2013. The efforts and determination have created breakthroughs and brought success for the year 2013, significantly contributes to the implementation of Petrovietnam’s 5-year strategic plan for the 2011-2015 period.

Thailand's PTT Aims for Higher 2014 Profit

Following the 2013 success, to 2014 - the year of the Horse, PetroVietnam continues a new race with the slogan "Be Drastic, Follow-up, Spurt, Overfulfill". With that spirit and determination, PetroVietnam completely believes to be able to fulfill the targets of 16.21 million tons of oil and 9.5 bil-

Thailand's top oil and gas company PTT Pcl said it aimed for 2014 net profit of 100 billion baht ($3.10 billion), up from last year's 94.6 billion baht, as its fifth gas separation plant will run at full capacity this year.

PTT's operations contribute 30 percent of profit, with the rest made up by subsidiaries, Chairman Pranpree Bahiddha-Nukura told reporters after a shareholder meeting.

Last year, its chemical unit, PTT Global Chemical Pcl , booked rising expenses over an oil leak in the eastern province of Rayong.

That dragged down PTT's profit.

The profit forecast was in line with market expectation. Statecontrolled PTT is expected to report a net profit of 105 billion baht for 2014, according to Thomson Reuters I/B/E/S. Chief Operation Officer Sarun Rungkasiri said he expected no growth in retail sales of oil products this year due to weak consumption, caused by prolonged political unrest and a slowing economy. This compared with growth of 2 percent to 3 percent in the previous years. ($1 = 32.2500 Thai baht). march/april 2014

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R e p o r t Industry News CIA 2005

Exxonmobil to Start Production at Record Number of New Oil and Gas Projects In 2014

Exxon Mobil Corporation expects to start production at a record 10 major projects in 2014, adding new capacity of approximately 300,000 net oil equivalent barrels per day and contributing to profitable production growth, Rex W. Tillerson, chairman and chief executive officer, said in early March.

“These projects exemplify our focus on maintaining a diversified portfolio and highlight our ability to grow profitable volumes,” Tillerson said at the company’s annual investment analyst meeting at the New York Stock Exchange.

“We are adding new volumes that improve our profitability mix with higher liquids and liquids linked natural gas volumes.

We’re also driving increased unit profitability through better fiscal terms and reducing low-margin barrel production.”

ExxonMobil’s capital spending will decline to $39.8 billion this year from a peak of $42.5 billion in 2013, Tillerson said.

Excluding potential acquisitions, capital expenditures are expected to average less than $37 billion per year from 2015 to 2017.

“We have financial flexibility to pursue potential strategic opportunities and maintain a disciplined and selective approach to capital that ensures any new investment will contribute

Industry News

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to robust cash flow growth,” Tillerson said.

A liquefied natural gas project in Papua New Guinea and the largest offshore oil and gas platform in Russia are among significant projects scheduled for startup this year. Others include a heavy oil expansion project in Canada and deepwater projects in the Gulf of Mexico.

ExxonMobil anticipates additional project startups in the next few years in several countries, including Australia, Indonesia, Canada, Nigeria and the United States. All of these projects are expected to add about 1 million net oil equivalent barrels per day by 2017. In North America, ExxonMobil’s near-term production outlook is made up of significant high-margin, lowrisk liquids growth. The company’s production outlook also reflects strategic choices made to improve unit profitability while maintaining disciplined capital allocation.

“We have a balanced and diversified portfolio that gives us a fundamental competitive advantage,” Tillerson said. “Resource and geographic diversity across the portfolio enables us to mitigate risks in a dynamic market environment and maximize profitability through changing business cycles.”

The company is pursuing m o re t h a n 1 2 0 h i g h - q u a l i t y projects to develop about 24 billion oil equivalent barrels of oil and natural gas.

ExxonMobil’s Downstream and Chemical businesses are focused on strengthening the portfolio and delivering sustained, industry-leading financial performance across the business cycle. Midstream investments in North America will expand ExxonMobil’s logistics capabilities to transport crude oil and finished products. Other advantaged projects will increase production of high-value products.

“In the Downstream and Chemical segments, we are diversifying feedstocks through our flexible and integrated system, continuously pursuing operating efficiencies and maximizing sales of higher-margin lubes, diesel and chemical products,” Tillerson said.

Mercator Petroleum in consortium with Oil India and Oilmax

Mercator Petroleum Ltd, Subsidiary of Mercator Limited, in consortium with Oil India Ltd., and Oilmax Energy Pvt. Ltd., has been chosen as the selected candidate by the Ministry of Energy of the Republic of the Union of Myanmar, for two shallow water offshore oil blocks, in the Myanmar Offshore Block Bidding Round – 2013.

The Consortium will enter into Production Sharing Contract for these blocks with Ministry of Energy of the Republic of the Union of Myanmar.

Mcdermott Wins PETRONAS Safe Contractor of the Year Award

McDermott International,

Visit our website at www.safan.com

Inc. was recently awarded “Best Contractor HSE Performer, 2013” by Malaysian oil company PETRONAS Carigali for work performed on its Kepodang Gas Development Project. “ I n d u s t r y re c o g n i t i o n i s the best way to demonstrate the success of McDermott’s Health, Safety, Environment and Security (“HSES”) culture,” said David Dickson, President and Chief Executive Officer. “McDermott has an exemplary safety record with-

in the offshore industry and strives for continual improvement and this recognition demonstrates the commitment we have to safety and our clients’ acknowledgment of the importance of safety during project execution.”

Wo r k p e r f o r m e d o n t h e Kepodang Gas Development Project included procurement, construction, installation and commissioning for a central production platform, a well head module, a satellite wellhead tower, 2.7 kilometers of

infield flow lines and an onshore receiving facility.

“McDermott management a n d t h e K e p o d a n g P ro j e c t Te a m a re e x t re m e l y p ro u d and honored to be recognized

by Petronas Carigali,” said Setio Hangodo, Project Director, who accepted the award at a recent ceremony on behalf of McDermott. ”It shows that McDermott and Petronas Carigali are aligned with HSES objectives and targets.”

PET

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Unlocking Coalbed Methane With natural gas gaining recognition as a major source of energy the role of CBM has come into the spotlight. Although it has been around for some time it is still a sector that is very young and this article outlines some associated issues as well as technologies pertinent to the sector.

C

oalbed methane is a form of natural gas extracted from coal beds. In recent decades it has become an important source of energy in United States, Canada, and other countries. Australia has rich deposits where it is known as coal seam gas.

t e c h n o l o g y CBM Feature

The term refers to methane adsorbed into the solid matrix of the coal. It is called 'sweet gas' because of its lack of hydrogen sulfide. The presence of this gas is well known from its occurrence in underground coal mining, where it presents a serious safety risk. Coalbed methane, often referred to as CBM, is distinct from typical sandstone or other conventional gas reservoirs, as the methane is stored within the coal by a process called adsorption. The methane is in a near-liquid state, lining the inside of pores within the coal (called the matrix). The open fractures in the coal (called the cleats) can also contain free gas or can be saturated with water.

Unlike much natural gas from conventional reservoirs, coalbed methane contains very little heavier hydrocarbons such as propane or butane, and no natural gas condensate. It often contains up to a few percent carbon dioxide. Some coal seams, such as those in certain areas of the Illawarra Coal Measures in NSW, Australia, contain little methane, with the predominant coal seam gas being carbon dioxide.

Methane (natural gas), while perhaps most closely related in our minds with petroleum, also occurs in association with coal. Scientific understanding of, and production experience with, coal-bed methane are both in the early learning stages. Much is

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yet to be learned about the controls on the occurrence and recoverability of coal-bed methane—the geologic, geochemical, engineering, technological, and economic factors, for example—and about the environmental implications of developing the resource. The coal-bed methane industry is still relatively young, and few studies exist of the development and evolution of an individual coal-bed methane play (a group of strata characterized by similar aspects of methane occurrence); thus, few models are available for planning the development of coal-bed methane resources on a broader scale.

During coalification, large quantities of methanerich gas are generated and stored within the coal on internal surfaces. Because coal has such a large internal surface area, it can store surprisingly large volumes of methane-rich gas; six or seven times as much gas as a conventional natural gas reservoir of equal rock volume can hold. In addition, much of the coal, and thus much of the methane, lies at shallow depths, making wells easy to drill and inexpensive to complete. With greater depth, increased pressure closes fractures (cleats) in the coal, which reduces permeability and the ability of the gas to move through and out of the coal. Exploration costs for coal-bed methane are low, and the wells are cost effective to drill.

Increased production of coal-bed methane, however, carries with it some technological and environmental difficulties and costs. In a conventional oil or gas reservoir, for example, gas lies on top of oil which, in turn, lies on top of water. An oil or gas well draws only from the petroleum that is extracted without producing a large volume of water.

But water permeates coal beds, and its pressure Visit our website at www.safan.com

traps methane within the coal. To produce methane from coal beds, water must be drawn off first, lowering the pressure so methane can flow out of the coal and to the well bore. This water, which is commonly saline but in some areas can be potable, must be disposed of in an environmentally acceptable manner.

Surface disposal of large volumes of potable water can affect streams and other habitats, and subsurface reinjection makes production more costly.

In addition, methane is a greenhouse gas; in the atmosphere it acts to trap heat and thus contributes to global warming.

Permeability is key factor for CBM. Coal itself is a low permeability reservoir. Almost all the permeability of a coal bed is usually considered to be due to fractures, which in coal are in the form of cleats and joints. The permeability of the coal matrix is negligible by comparison. Coal cleats are of two types: butt cleats and face cleats, which occur at nearly right angles. The face cleats are continuous and provide paths of higher permeability while butt cleats are discontinuous and end at face cleats. Joints are larger fractures through the coal that may cross lithological boundaries. Hence, on a small scale, fluid flow through coal bed methane reservoirs usually follows rectangular paths. The ratio of permeabilities in the face cleat direction over the butt cleat direction may range from 1:1 to 17:1. Because of this anisotropic permeability, drainage areas around coal bed methane wells are often elliptical in shape.

Gas contained in coal bed methane is mainly methane and trace quantities of ethane, nitrogen, carbon dioxide and few other gases. Intrinsic properties of coal as found in nature determine the amount of gas that can be recovered. The porosity of coal bed reservoirs is usually very small, ranging from 0.1 to 10%.

Adsorption capacity of coal is defined as the volume of gas adsorbed per unit mass of coal usually expressed in SCF (standard cubic feet, the volume at standard pressure and temperature conditions) gas/ton of coal. The capacity to adsorb depends on the rank and quality of coal.

The range is usually between 100 to 800 SCF/ton

for most coal seams found in the US. Most of the gas in coal beds is in the adsorbed form. When the reservoir is put into production, water in the fracture spaces is pumped off first. This leads to a reduction of pressure enhancing desorption of gas from the matrix.

As discussed before, the fracture permeability acts as the major channel for the gas to flow. The higher the permeability, higher is the gas production. For most coal seams found in the US, the permeability lies in the range of 0.1 to 50 milliDarcies.

The permeability of fractured reservoirs changes with the stress applied to them. Coal displays a stress-sensitive permeability and this process plays an important role during stimulation and production operations.

The thickness of the formation may not be directly proportional to the volume of gas produced in some areas.

For Example: It has been observed in the Cherokee Basin in Southeast Kansas that a well with a single zone of 1–2 ft of pay can produce excellent gas rates, whereas an alternative formation with twice the thickness can produce next to nothing.

Some coal (and shale) formations may have high gas concentrations regardless of the formation's thickness, probably due to other factors of the area's geology.

The pressure difference between the well block and the sand face should be as high as possible as is the case with any producing reservoir in general.

Other affecting parameters include coal density, initial gas phase concentration, critical gas saturation, irreducible water saturation, relative permeability to water and gas at conditions of Sw = 1.0 and Sg = 1-Swirreducible respectively.

Promising coal basins and those under development contain a significant part of the global coal resources accompanied by methane. Coalbed methane resources are commensurate with the world’s conventional gas resources. Therefore, such basins shall be considered as the CBM basins that are subject to comprehensive phased development with preliminary large-scale methane production. march/april 2014

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Scientifically proven assessment of the coalbearing formations’ role as the major sources of methane and locations for its accumulation in the Earth’s crust opens up new and wide horizons in building up the resources of hydrocarbon gases. Methane, being a most hazardous by-product of coal, is becoming a valuable natural resource to be produced from coal mines as an independent commercial product or as a by-product, in the process of comprehensive phased development of gas-bearing coal fields.

Peculiarities of CBM Fields’ Development

It should be noted that not every type of coal is suitable for methane production. Thus, longflaming brown coal fields are featured with low methane content. Anthracite coal is characterized with high gas content; however, it cannot be recovered due to high density and very low permeability of the deposit. The coals that fall somewhere in between the brown coals and the anthracite coals are attributable to the most favorable ones for methane production. This kind of coal is deposited in Kuzbass.

There are two essentially different ways of CBM recovery: from coal mines (existing mine take areas) and from CBM wells. CBM recovery from coal mines is an integral part of the deep mining technique intended for methane emissions lowering and its explosion prevention.

When produced from coal mines, the amount of CBM is small and is mainly used for technological purposes of coal producers. This technique is impeded by considerable fluctuations in the volume of the gas-air mixture received and methane concentration in it.

Commercial CBM development is associated with specific technologies of gas recovery intensification.

Extraction

Since CBM travels with ground water in coal seams, extraction of CBM involves pumping available water from the seam in order to reduce the water pressure that holds gas in the seam.

CBM has very low solubility in water and readily separates as pressure decreases, allowing it to be piped out of the well separately from the water.

CBM Feature

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Water moving from the coal seam to the well bore encourages gas migration toward the well.

CBM producers try not to dewater the coal seam, but rather seek to decrease the water pressure (or head of water) in the coal seam to just above the top of the seam. However, sometimes the water level drops into the coal seam.

There are two popular methods of estimating recoverable methane gas from a coal seam. One method requires estimating methane reserves by boring to the top of the coal seam, then extracting a core from the coal. The amount of methane recovered from the coal core is used to estimate gas content per unit volume of coal. If a number of cores are drilled and methane gas release is observed, one can estimate the amount of gas available in a region. The limitations to this method are: 1) there is much disturbance to the coal seam core before gas release is measured; 2) it is expensive and 3) not every region of potential CBM development has been drilled and explored.

Another method of estimation is through a series of calculations based on information already known about the coal in the region and the feasibility of CBM development. For instance, the Montana Bureau of Mines and Geology estimated the amount of recoverable CBM in the Powder River Basin using the following information: • A coal seam has favorable reserves if it produces 50-70 ft3 per ton of coal.

• CBM extraction is economical at 50 ft3 per ton of coal when a coal seam is 20 feet thick or more.

• Coal bed methane exists only in areas where the dominant chemistry of the water in the coal seam is sodium bicarbonate and where the coal seam is buried deeply enough to maintain sufficient water pressure to hold the gas in place.

To extract the gas, a steel-encased hole is drilled into the coal seam (100–1500 meters below ground).

As the pressure within the coal seam declines due to natural production or the pumping of water from the coalbed, both gas and 'produced water' come to the surface through tubing. Then the gas is sent to a compressor station and into natural gas pipelines. The 'produced water' is either reinjected Visit our website at www.safan.com

into isolated formations, released into streams, used for irrigation, or sent to evaporation ponds.

The water typically contains dissolved solids such as sodium bicarbonate and chloride.

Coalbed methane wells often produce at lower gas rates than conventional reservoirs, typically peaking at near 300,000 cubic feet (8,500 m3) per day (about 0.100 m続/s), and can have large initial costs.

The production profiles of CBM wells are typically characterized by a "negative decline" in which the gas production rate initially increases as the water is pumped off and gas begins to desorb and flow.

A dry CBM well is similar to a standard gas well.

The methane desorption process follows a curve (of gas content vs. reservoir pressure) called a Langmuir isotherm. The isotherm can be analytically described by a maximum gas content (at infinite pressure), and the pressure at which half that gas exists within the coal. These parameters (called the Langmuir volume and Langmuir pressure, respectively) are properties of the coal, and vary widely. A coal in Alabama and a coal in Colorado may have radically different Langmuir parameters, despite otherwise similar coal properties.

As production occurs from a coal reservoir, the changes in pressure are believed to cause changes in the porosity and permeability of the coal. This is commonly known as matrix shrinkage/swelling. As the gas is desorbed, the pressure exerted by the gas inside the pores decreases, causing them to shrink in size and restricting gas flow through the coal. As the pores shrink, the overall matrix shrinks as well, which may eventually increase the space the gas can travel through (the cleats), increasing gas flow.

The potential of a particular coalbed as a CBM source depends on the following criteria. Cleat density/intensity: cleats are joints confined within coal sheets. They impart permeability to the coal seam. A high cleat density is required for profitable exploitation of CBM. Also important is the maceral composition: maceral is a microscopic, homogeneous, petrographic entity of a corresponding sedimentary rock. A high vitrinite composition is ideal for CBM extraction, while inertinite hampers the same.

The rank of coal has also been linked to CBM content: a vitrinite reflectance of 0.8-1.5% has been found to imply higher productivity of the coalbed.

The gas composition must be considered, because natural gas appliances are designed for gas with a heating value of about 1000 BTU per cubic foot, or nearly pure methane. If the gas contains more than a few percent non-flammable gases such as nitrogen or carbon dioxide, either these will have to be removed or it will have to be blended with higherBTU gas to achieve pipeline quality. If the methane composition of the coalbed gas is less than 92%, it may not be commercially marketable.

Associated Problems

CBM wells are connected by a network of roads, pipelines, and compressor stations. Over time, wells may be spaced more closely in order to extract the remaining methane. Additionally, the produced water may contain undesirable concentrations of dissolved substances. Water withdrawal may depress aquifers over a large area and affect groundwater flows.

The environmental impacts of CBM development are considered by various governmental bodies during the permitting process and operation, which provide opportunities for public comment and intervention. Operators are required to obtain building permits for roads, pipelines and structures, obtain wastewater (produced water) discharge permits, and prepare Environmental Impact Statements. As with other natural resource utilization activities, the application and effectiveness of environmental laws, regulation, and enforcement vary with location.

Violations of applicable laws and regulations are addressed through regulatory bodies and criminal and civil judicial proceedings.

In a coal-bed methane well, water is produced in large volumes, especially in the early stages of production; as the amount of water in the coal decreases, gas production increases. The water must be disposed of safely. Most frequently, water is reinjected into subsurface rock formations. In some cases, the water is allowed to flow into surficial drainages or is put into evaporation ponds. In cold regions, it is possible to freeze the water in the winmarch/april 2014

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ter, collect the salts that separate out, and dispose of or utilize them independently of the water, which can be discharged.

Methane in the atmosphere has been increasing at a rate of 1 percent per year during the past 15 years. Natural systems—wetlands and swamps, for example, and decomposing forest materials— account for about 40 percent of the methane released to the atmosphere. The balance is the result of human activity, though only about 10 percent of this is attributed to methane production; the remainder comes from such activities as rice cultivation, livestock, landfills, and biomass burning.

Production of methane from coal beds may actually reduce methane emissions to the atmosphere by removing the gas that is otherwise released during coal mining.

In some areas, methane migration may have contaminated ground-water sources, and methane may have migrated into residential neighborhoods. The controls on methane migration, however, are unclear. Some contamination may come from migration of methane along natural fractures; some may come from older gas wells that tapped reservoirs in sandstones associated with the coals.

Some may come from new coal-bed methane wells.

Reports from the 1800’s document gas bubbles in water wells, in streams, and in fields after heavy rains; this evidence suggests that migration has always existed. It has now become a problem because of new residential development near the methane migration pathways.

CBM in Asia

Indonesia has one of the largest CBM resources in the world with a potential 453 trillion cubic feet ("Tcf"), more than double the country's natural gas reserves (Society of Petroleum Engineers, 2004).

The South Sumatra Basin, the largest CBM basin in Indonesia, is estimated to contain in-place resources of approximately 183 Tcf; and the Kutai Basin, the third largest CBM basin in Indonesia, is estimated to contain in-place resources of

CBM Feature

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approximately 80 Tcf (SPE, 2004). Between May 2008 and August 2009, 15 CBM PSCs were granted by the Government of Indonesia, representing exploration commitments of US$95.68 million over the next 3 years.

CBM is also a key potential source of energy for Australia, India and China. The KG-D6 field being developed by RIL is one example of the importance of CBM to India. Some key players involved in CBM E&P are Shell, Dart Energy, RIL, and CBM Asia, and MedcoEnergi.

CBM Asia Development Corp. ("CBM Asia" or the "Company") is a Canadian-based unconventional gas company with significant coalbed methane ("CBM") exploration and development opportunities in Indonesia. The Company has entered into a binding letter of intent to acquire a participating interest in a production sharing contract ("PSC") for CBM on a 58,349 hectare block located in the South Sumatra Basin where initial exploration drilling of a production test well commenced in the second half of 2009. The Company has committed to fund an initial US$3.25 million in exploration expenditures on the Sekayu PSC to prove reserves and submit a Plan of Development to the Government of Indonesia. The Company also has an 18% net working interest in a CBM PSC on a 76,000 hectare block located in the Kutai Basin of East Kalimantan. As geotechnical lead, the Company is responsible for directing a US$5.6 million exploration and appraisal program over the next three years (to November 2011), to determine commercial feasibility of CBM production for the Kutai-West PSC and submit a Plan of Development to the Government of Indonesia. The Company holds 28% net participating interest in a second 56,500 hectare block, the Kutai II, also in the prolific Kutai Basin.

Progression

I feel that the proof of CBM’s commercial viability is the fact that vendors are developing technology to be used primarily for CBM E&P. Honeywell has developed the Well Performance Monitor for Coal Bed Methane Visit our website at www.safan.com

which brings all the established benefits of the conventional solution to the rapidly developing coal seam gas market.

Well Performance Monitor for CBM recognizes the specific challenges facing operators of coal bed methane wells. Operations typically have longer lead times to economic production and a limited workforce managing hundreds to thousands of wells with shorter well lifecycles. Throughout the well’s lifecycle, it is critical to quickly identify well issues and focus efforts where it is most needed to avoid costly failures and deferred production.

Inflatable Packers International is another example. IPI claims its development into the coal bed methane market is a logical extension of its expertise in water well technology, as draining water from coal seams releases methane. Coal bed methane reserves may be evaluated and extracted for solely commercial gas supply, drainedsolely for mine safety (mine degasification) , or for both reasons.

The IPI CBM Test Tool consists of a straddle (double) packer system including setting tool intended for use in CBM bores. The basic philosophy is to provide an integrated test tool that allows isolation of specific hole sections for inflow testing (similar to an oilfield DST Tool). The entire tool comprises: • A three position Setting/Shut-in Tool • A top packer • A perforated injection sub, crossover and extension subs • A bottom packer.

The system is designed to be run on rods, with the Setting/Shut-in tool mounted directly on the top of the top packer and the rods being filled with water during run-in. Pumping down through the rods inflates the packers. Shifting the tool down allows pump through or fluid extraction (via air-lift or similar) for testing. Shifting back up a minimum distance places the tool in the Shut-in position and a further upward movement shifts it back up to the packer deflation position.

The bottom packer is inflated by means of the bottom packer crossover and any extension subs or

by running ancillary tubes in the tool/hole annulus between the packers as appropriate. Lengthening of the test zone is accomplished by adding additional extension subs to the desired length.

Halliburton has also recognized that CBM E&P needs unique tools and has developed a portfolio for the sector. Their claim is that through years of working closely with their customers to commercialize coalbed methane (CBM), they have identified the top enabling technologies that, when coupled with experience and the right processes, offer the best chance for CBM projects to reach their full life cycle potential.

Microhole technologies and Casing Drilling are further examples of technologies being developed to serve the CBM sector.

Conclusion

Burning methane adds considerably less carbon dioxide to the atmosphere than does the burning of coal, and production of methane from coals prior to mining reduces the amount of methane released to the atmosphere during the mining process. Producing methane then can serve a double purpose in the campaign to reduce the release of gases that contribute to global warming. Increased production and use of coalbed methane, however, require a new understanding of its origin and distribution within coals, new approaches that will provide a variety of appropriate alternatives for the disposal of produced waters, and engineering studies that will augment the current understanding and recovery of this unique resource. Studies now underway, as part of the USGS Energy Resources Program, PET speak of all these issues.

ENQUIRY NUMBER:

03/04-01

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51

Offshore Vessel Connectivity Today and Tomorrow The maritime satcoms landscape is shifting with a new generation of services poised to come online. Offshore oil & gas users are today among the heaviest bandwidth consumers, with a diverse range of operations all depending on VSAT services to enhance applications from vessel and fleet management through to the delivery of seismic data.

S

imon Møkster Shipping’s 23-strong fleet of offshore supply and specialist vessels use the Microsoft Lync platform through customised VSAT service provided by service provider Marlink. The company’s Sealink service has enabled Simon Møkster, the established Norwegian offshore vessel operator to roll-out Microsoft’s standardised business collaboration and communication platform across its organisation on land and at sea, resulting in operational benefits in addition to substantial savings in the cost of crew calling.

t e c h n o l o g y Communication Systems

Using Lync via Sealink enables bridge and engine room teams to access low-cost and reliable, telephony, video conferencing, instant messaging and data sharing. Sealink ensures high uptime, meeting Simon Møkster’s requirements for continuous availability of the Lync platform in order to ensure high level fleet management and communication capabilities. Custom dynamic allocation of dedicated bandwidth on the Sealink service enhances reliability, especially for bandwidth hungry applications.

As a standardised, non-maritime specific software, Lync enables significant IT efficiencies.

Simon Møkster can collaborate across its whole organisation to a greater degree than before, making every one of its vessels a ‘remote office’.

The file and document sharing, and communication aspects have provided tangible improvements in ship operations but in order for them

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to function fully, the company needs a secure and reliable communication network. Sealink provides this with the added benefit that Simon Møkster can work closely with Marlink people to ensure availability and compatibility with the vessel and shore IT infrastructure.

Lync is fully integrated with the Simon Møkster company telephone system, so calls from terrestrial and mobile networks, and other Lync users can be made to vessels and received via Lync. A unique VoIP solution has also been implemented for crew members from the Faroe Islands, which reduces their calling costs by at least 50%.

With antenna testing collaboration aboard the ‘Stril Myster’, Simon Møkster and Marlink already have a strong working relationship which provides real insight into offshore vessel communication needs.

Customer communications

The Simon Møkster case shows the importance of reliable broadband for offshore vessels. In addition to fleet management and communication, VSAT offers significant capabilities including support for engineers, maintenance and diagnostics to members of the crew staying in touch with friends and relatives. For many companies operating vessels offshore, the availability of always-on, reliable connectivity is critical to the smooth operation and success of the business.

Visit our website at www.safan.com

For GC Rieber Shipping, a global shipping company that specialises in the operation of vessels within subsea, ice/support and marine seismic sectors, communications is an integral part of satisfying its customers’ needs as well as improving efficiency of the company’s operations. The primary applications for connectivity are email, Internet access and cost-effective voice for telephone calls as well as replication of PMS and QHSE databases. It is all tied together with in-house systems onshore, so that all activity on the vessel is immediately replicated to the office and all office activity is immediately dispatched to the vessel, which greatly improves efficiency of processes.

According to GC Rieber Shipping, who use VSAT connectivity provided by Marlink, bandwidth over VSAT is prioritised to customers hiring the vessels, which commonly includes seismic, subsea and oil research companies as well as research departments within governments or universities. For example, if there is a charterer that’s hired a vessel, he could have his own customers on board who each have their own specific needs for satellite communications. There are therefore a wide-range of requirements to accommodate and it is an integral part of GC Reiber’s strategy to all customers’ needs are catered for.

Marlink’s Sealink VSAT system is installed on board the majority of GC Rieber Shipping’s vessels. As satellite communications is so core to GC Rieber Shipping’s operations, it is imperative that always-on connectivity is reliable and flexible to meet customers’ multitude of requirements.

Through the VSAT’s bandwidth, service engineers are able to log on to the ship’s systems remotely from the office ashore to monitor and adjust software on board. This prevents unnecessary travel to the vessel, which reduces costs.

It also eliminates potential unnecessary downtime because service engineers can look at the problem immediately.

According to GC Rieber Shipping, Marlink’s satellite communications solutions also provide exceptional flexibility. Dual 9797 C-band and Kuband antennas are installed so that customers can

take advantage of both C-band and Ku-band coverage to meet their individual needs. The flexibility of the dual antenna approach ensures that both the robustness and greater coverage of the C-band VSAT is available to customers when it is required.

In addition, Ku-band coverage is also available so that if costs are a focus, customers can switch to this when sailing in Ku-band coverage spots.

Crew Welfare

Communications as a tool for boosting crew morale is still core to the strategy for many offshore businesses with demands from crew becoming increasingly focused on data, for web access and social applications such as Facebook and Twitter.

In addition to its customers, GC Rieber Shipping’s vessels have their own business network of crew on board, including the Captain, Chief Engineer and several officers.

Without investing in communications for crew, it is much harder to attract and retain the best crew.

On GC Reiber vessels, all the crew have equal access to both Internet and telephone regardless of whether they are a charterer, own crew or the end client. The VSAT solution allows the crew to have free access to Internet and cheap calls to their home so that they can keep in touch with their friends and families easily. Crew can also keep up with personal administration, for instance, online banking and check local newspapers so they can stay up to date with what’s happening at home.

This means that even though crew are far from home, they still have access to their home lives through the VSAT. For GC Rieber Shipping, a company that specialises in the transportation of information for its customers, the availability of satellite communications has become fundamental to the successful operation of the business. Marlink’s Sealink service has enabled GC Reiber to tie all its vessels’ applications directly to its office applications, significantly increasing interaction between land and sea. Each vessel provides important information on a daily basis and the capability for this data to be continuously replicated in real-time significantly enhances GC Reiber’s value offering to customers. march/april 2014

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Bandwidth, more bandwidth

At sea, just as on land, the hunger for more bandwidth is ever present. The so-called Digital Oilfield is a brave new era with new technology developed for monitoring and collaboration changing the way many fields operate. Without the communication bandwidth enabled by satcoms though, the impact this technology has made would not be as evident.

A reliable, high bandwidth satellite link to land signals enables the distributed workforce. Experts can be based on land, in the office at home even and work across multiple projects, ensuring optimal efficiency and safer operations. They can view real-time or near real-time data from every aspect of a seabed survey or production operations.

From seismic survey data to downhole sensors, the amount of data being generated is staggering.

Without connectivity, the survey, drilling, riser or plethora of other sensor data vital to operations stays on board the vessel or platform until it can be manually delivered. That same expert who can now provide his services for decision support almost instantly would be living from a suitcase, getting familiar with airport lounges and dedicating themselves to a single job.

The problem with bandwidth though, is that once you have it, you want more. And users of satcoms in the oil & gas industry are addicted to data.

None more so than those tasked with exploring for new prospects or confirming the validity of those already found. The seismic survey industry in fact has the potential to become the biggest consumer of bandwidth at sea. The potential for cost savings generated by having survey data sent to shore as, or just after it’s generated are significant. Perhaps an important subsea feature is uncovered, which would mean the survey route should be changed.

If the data isn’t available to decision makers on shore, then the ship may have to return to port before it’s noticed and then sent back out. Considering the investment in survey vessel chartering, this can be quite uneconomic. So it’s better just to change the survey plan on the fly.

Based on this, there is a certain drive in the survey sector for more bandwidth in order to de-

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liver seismic data to shore. As an example, Marlink successfully completed delivery of Ku-band VSAT services based on a 12 Mbit/s dedicated return link for the Atlantic Explorer, a Petroleum Geo Services (PGS) owned seismic survey vessel. The high throughput link was an upgrade to Atlantic Explorer’s existing Sealink customized VSAT service.

The service was used during a four week North Sea survey project, enabling seamless transfer of survey data to shore where it could be reviewed and addressed whilst Atlantic Explorer was still at sea. This enabled survey schedules to be amended based on results as they were generated, saving time, costs and resources for PGS’ client as there was no need to wait for data to be delivered on return to port or collected by a helicopter.

Taking into account overheads, packet loss for instance, the link enabled throughput of approx.

5GB per hour. To put it into context, this is about 50 times more throughput than an average offshore vessel needs for heavy operational and crew use. A link of this scale was necessary in order to facilitate the transfer of survey data. The project was a success, with the link providing massive amounts of bandwidth that enabled PGS and its client to conduct a highly operationally and cost efficient offshore survey.

The connection was ordered by PGS mid May 2013 and was live by the end of June using the existing 1.5 m Ku-band antenna on board Atlantic Explorer. A Marlink engineer installed a new 40W BUC (Block Upconverter) prior to the survey, to enable the higher throughput, which was activated whilst the vessel was out at sea. The configuration and service provision reflects Marlink’s approach to project based VSAT, where it can quickly provide extended capabilities for vessels requesting extra temporary or permanent bandwidth.

The Atlantic Explorer project represents the very cutting-edge of what is known as customized VSAT; the kind of services used by the offshore industry because every platform and vessel has different requirements. This kind of high-level connectivity is not an off-the-shelf Visit our website at www.safan.com

product. It supported PGS in providing a very high-end service to its client and in the very competitive seismic survey market, they were able to offer very advanced capabilities.

Coming next

Aside from the cruise sector which essentially needs broadband for floating towns, Seismic survey vessels are potentially the biggest bandwidth consumers of all commercial operators at sea. If the seismic industry follows PGS’ lead, then these vessels will be leading the field in terms of bandwidth used, and connectivity speeds. But as more and more creative software applications are developed for offshore vessels and their operations, the need for bandwidth will continue to grow. This, alongside demands in the shipping and cruise sectors is a key motivator for the introduction of new High Throughput Satellite (HTS) services. Two HTS networks offering Ka-band or Ku-band VSAT services are planned to go online later in 2014 – Inmarsat’s Global Xpress and Intelsat’s EpicNG. They will flood the airwaves with huge amounts of extra bandwidth, which will feed the insatiable demand for data from the offshore and shipping sectors.

With these new satellites forthcoming and a plethora of services already offering high bandwidth and connection speeds, choosing the best price vs performance for vessels and fleets will need careful consideration and the support of a service provider that understands your needs.

Marlink has been providing communication services to the offshore sector for more than 25 years as the in-house satcoms service provider of Airbus Defence and Space (previously Astrium Services and Vizada).

As the largest entity providing satcoms to maritime users, Airbus Defence and Space has recently re-worked its entire offering, to ensure it can offer a clear route into current high speed and forthcoming HTS services. Called AuroraGlobal, it is seen as the ‘network of networks’ as it encompasses all services available on land and at sea. Offshore users will have access to AuroraMaritime, a portfolio of services that include the capability to achieve the kinds of throughput and speeds promised by HTS services today,

without the need to change existing on board hardware. Built into the offering though, is a simple migration path to Global Xpress and EpicNG services, giving operators and vessel owners the flexibility to wait and see which of the new, high bandwidth services suit them.

AuroraMaritime also includes the latest XChange communications management platform enables seamless management of the switch between VSAT and the L-band satcoms services that are included for back-up as standard. Maritime decision makers and IT managers can remotely manage their ships’ IT and operational communications with simplified network administration on board and across fleets with XChange. It also includes the unique BYOD (bring your own device) Wi-Fi solution, allowing shipping companies to provide crew with the most cost-effective voice and Internet services delivered to their own smartphones, laptops and tablets. This aspect will of course be a significant capability when trying to attract and retain the best crew.

The idea behind AuroraGlobal is to offer stateof-the-art VSAT services, with the largest coverage and cost-effective high-speed broadband available today. It makes choosing the right service easier and provides access to practically all communication networks relevant to offshore operations, even as far as the L-band back-up. In general, the services within AuroraMaritime offer twice as much speed or data, for the same investment being made today, so Airbus Defence and Space is enabling maritime users to embrace more efficient IT applications for all offshore operations, while also improving crew connectivity and enhancing the cost versus performance graph for offshore vessel communication services. And with the diverse demands and applications described above, this can only be a good thing for the continuing growth of PET the offshore sector.

This publication thanks Mr. Charlie Ransford, Business Development Manager, Marlink Asia Pacific, for providing this article.

ENQUIRY NUMBER:

03/04-02

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C o n f e r e n c e s

MODUC 2014 – A Resounding Success

T

he 3rd Mobile Offshore Drilling Units Convention (MODUC) 2014 has once again set a successful networking formula for oil and gas professionals to explore new business ideas. MODUC, organized by PetroMin and held annually, is the only event in Asia focused exclusively on offshore mobile rigs.

University (Singapore) - followed by Mr. Yves De Leeneer, Chairman, Joint Branch of the Institute of Marine Engineering Science and Technology and The Royal Institute of Naval Architects who hosted the second session of presenters.

The two-day event held at Resort World Sentosa's convention centre attracted local and overseas delegates from Keppel Deepwater Technology Group, Maersk Drilling,Kongsberg Maritime, GE Oil & Gas, ABB, Lloyd's Register Energy, DNV.GL – Maritime, ABS, Total Maritime Solutions, Check-6, and more.

& E x h i b i t i o n s INAMARINE MODUC Preview Review

Mr. Murthy Pasumarthy, Design Engineer, Keppel Deepwater Technology Group; Mr. Ian Partridge, Regional Engineering Manager, TWI Services Sdn Bhd; Mr. Ted Williams, Client Manager, Total Maritime Solutions – Check-6; and Mr. Shreenaath Natarajan, Technical Director, 2H Offshore (Asia Pacific) Sdn Bhd were among several other speakers who presented technical papers at MODUC 2014.

Mr. Peter Noble, President, Society of Naval Architects and Marine Engineers

Day one was chaired by Mr. Peter Noble, President, Society of Naval Architects and Marine Engineers, and Dr. Arun Dev, Senior Lecturer, Newcastle

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MODUC 2014 enabled participants to exchange views and share knowledge on areas for future growth in the mobile offshore drilling units sector, said Mr. Ted Williams, Client Manager, Total Maritime Solutions, Check-6, “We not only got to compare notes and share ideas on evolving technology and opportunities, but we also got to connect and get to know each other. Through this event, I was able to connect with leaders in the industry Visit our website at www.safan.com

that I would not have had the opportunity to meet in another manner.”

Dr. Arun Dev, Senior Lecturer, Newcastle University, MODUC Chairman

Conference topics were centred on the latest state-of-the-art, ultra offshore drilling components designed for operation in all environmental conditions.

Technology, offshore drilling systems, navigation control, production and processing, electrical and instrumentation and human resource development were some of the topics discussed. One of the most discussed topics was the advancements in BOPs, with related presentations garnering a deluge of questions from the delegates.

Mr. Chris Tolleson, System and Lead Specialist at Lloyd’s Register Global Technology Centre Pte Ltd, delivered a presentation on advancing FEA technology on BOP shear modeling highlighted the rise of drilling challenges, and the importance for BOP to keep up with the changes, so as to develop better quality drill pipe material properties.

“I haven't seen a presentation on modeling of shearing, therefore found it to be valuable,” said Mr. David Dietz, Technical Sales, GE Oil & Gas, Drilling Systems. “I became aware that there was a lot of work in this area. It is a challenging task to utilize modeling in lieu of testing for validation of shearing capability, which would lead to cost savings for our customers and free up capacity in

our test and demonstration facility,” he said, commenting on Mr. Tolleson’s presentation.

Mr. Daniel Aneljung, Project Manager from GVA discussed current challenges for designers when facing mid water and deep-water areas.

Meanwhile Kongsberg Maritime's Norwegian Regional Sales and Marketing Manager (Asia), Mr. Roar Marthiniussen shared his views on the development in hydroacoustic positioning through HIPAP system and its integration with using INS sensors in the HAIN system.

”I enjoyed all of the presentations, especially the panel discussions. I found them to be valuable. Of particular interest were the presentations that displayed the arriving technologies, which helped oil and gas production to increase and expand the existing capabilities.”

Ted Williams, Client Manager, Total Maritime Solutions, Check-6.

The event was attended by industry specialists from around the world and they felt that MODUC 2014 was a superb investment of their time and effort.

Most agreed that the topics and papers presented were current and insightful and that they would consider the event to be success, also expressing their eagerness to attend MODUC 2015.

For information on upcoming oil and gas technical networking conferences for 2014 visit PET www.safan.com.

ENQUIRY NUMBER:

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57

C o n f e r e n c e s & E x h i b i t i o n s INAMARINE Preview

INAMARINE 2014

T

he resounding success of INAMARINE 2013, held along with INACOATING 2013, attracted 221 exhibiting companies from 15 countries, 11,800 trade attendees from over 31 countries and occupied total area 8,000 sqm gross, has further proved as the Indonesia’s largest trade show for marine engineering & equipment, shipyards, shipbuilding and offshore. The Expo has become the most influence marketplace to boost sales and gain exposure as well as meeting with key decision makers and potential buyers in maritime industry.

As the most influential and comprehensive event in Indonesia, INAMARINE 2014 taking place from 13 – 15 May 2014 at the Jakarta International Expo (JIExpo), Jakarta – Indonesia will be expanded to be bigger and qualified networking platform of the maritime industry to generate more qualified visitors and international platform.

INAMARINE 2014 will be co-locating with INAWELDING 2014, INAPORT 2014 and IIML 2014 (Material Handling and Logistic).

It will be notably served as one of the world’s most prospective one-stop exhibition for suppliers and any shipyard, shipbuilding, offshore, port, welding, coating and other related industries.

Date:

13 – 15 May 2014

Industry:

Shipbuilding, offshore, marine, machinery, equipment

Venue:

Jakarta International Expo

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Country:

(JIExpo) Kemayoran

Organiser:

PT Global Expo Management (GEM Indonesia)

Indonesia

Event Website: www.inamarine-exhibition.

net

Organizer Contact Information

Perkantoran Mutiara Taman Palem, Blok C5 No.28 – 29 . Jl. Kamal Raya Outer Ring Road – Jakarta Barat 11730, Indonesia.

Tel: +62-21-54358118 Fax: +62-21-54358119.

Email: info@gem-indonesia.net.

PET

`03/04-05

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JULY 2014

JUNE 2014 SUBSEA Asia 2014 11 June 2014 (Conference) 12 - 13 June 2014 (Exhibition) Venue: Kuala Lumpur Convention Centre, Malaysia Contact Person: Mr Lim Cha Cheng Tel: (60) 3 4041 0311 Fax: (60) 3 4043 7241 Email: lcc@mesallworld. com Website: www.subseaasia. org 4th Dynamic Positioning Asia Conference 2014 23 - 24 June 2014 (Resorts World Sentosa Convention Center, Singapore) Tel: (65) 6222 3422 Fax: (65) 6222 5587 Email: natalialim@safan.com

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DECEMBER 2014 OSEA 2014 2 – 5 December 2014 (Marina Bay Sands, Singapore) Contact: Chua Buck Cheng Tel: (65) 6233 6638 Fax: (65) 6233 6633 Email: osea@sesallworld.com Website: www.osea-asia.com

Calendar of Events 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

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21

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27

DNV GL

7

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9

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15

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35

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23

Norgren Ltd

25

Olio Resources Sdn Bhd

29

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31

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11

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13

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1

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3

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Barrel.............................................bbl Thousand barrels...........................Mb Million barrels................................MMb Barrels per day..............................b/d Thousand barrels per day..............Mb/d Million barrels per day ..................MMb/d Metric ton.......................................tonne Thousand tonnes...........................Mt

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Conventions used within this magazine

Million tonnes.................................MMt Tonnes per day..............................t/d Tonnes per year.............................t/y, tpa Thousand tonnes per year.............Mt/y Million tonnes per year..................MMt/y Tonnes of oil equivalent.................toe Thousand tonnes of oil equivalent.Mtoe Million tonnes of oil equivalent.......MMtoe

march/april 2014

Cubic feet......................................cf Thousand cubic feet......................Mcf Million cubic feet............................MMcf Billion cubic feet.............................Bcf Trillion cubic feet............................Tcf Cubic feet per day.........................cfd Million cubic feet per day...............MMcfd Billion cubic feet per day................Bcfd British Thermal Unit.......................Btu

Watt...............................................W KiloWatt.........................................kW MegaWatt......................................MW GigaWatt........................................GW Watt-hour.......................................Wh KiloWatt-hour.................................kWh MegaWatt-hour..............................MWh GigaWatt-hour...............................GWh

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