Executive Interview Nanang Untung “President Director & CEO PT Badak NGL”

January - February 2014

Continued on page 6 WIRELINE SYSTEMS Advertisements Contents Dear SPE Members; 2 Contents & Advertisement SPE Java Section Newsletter is issued every other 4 Chairman’s Message month; they are printed 1,500 copies per issue, circulated among members, industry leaders, stakeholders (staff and 5 Distinguished Lecturer manager), and students. 6 Profile: Nanang Untung President Director & CEO PT Badak NGL In order to improve the content of our Newsletter, we urge you to send us an article worth sharing to update and enrich 12 Linking LNG Price with Oil Price & LNG Process our reader (at no cost to you), with application of certain 13 The Story of Vico technology, and/or CSR activity which made an impact on our industry. 14 Mahakam: Continuous Improvement in Managing Challenging Fields Development We would also like to invite your Company to place an 17 Aceh Operations Mature Field Management: Advertorial, which serves as a showcase, at the same time Arun Gas Field & North Sumatera Offshore to cover the cost of printing the Newsletter accordingly to (NSO) the following fee structure with effect July 2012: 23 Tangguh the Controversy & LNG Facts 24 LNG for Power Generation is a Luxury that Full page Printing Charges in USD Indonesia Can’t Afford Old Rate No. of Issue New Rate 385 1 400/issue 26 LNG Stories & Indonesia’s (Shrinking) LNG Industry 2 375/issue = 750 3 350/issue = 1,050 32 Nusantara Regas: Pioneering the First LNG 4 325/issue = 1.300 FRSU in Asia Pacific 5 300/issue = 1,500 34 Sengkang Mid Scale LNG Development 6 275/issue = 1,650 37 Mini LNG Plant: Monetizing Marginal & Standed Gas Field Half-a-page Printing Charges in USD Old Rate No. of Issue New Rate 40 Introducing Mini LNG to Indonesia 220 1 250/issue 44 Economic Small Scale LNG Plant 2 235/issue = 470 Implementation With Cluster LNG Technology 3 210/issue = 630 Minimize risk in 51 Marginal Gas Development With Compact 4 200/issue = 800 Motor-Driven LNG 5 190/issue = 950 high-value wells. 6 180/issue = 1,080 54 Delving into The Novelty of The Masela Abadi FLNG Project High-value wells hold the promise of great returns—or the potential for TJHOJæDBOUMPTTFT%BUBRVBMJUZDBONBLFUIFEJGGFSFODF5IF8FBUIFSGPSE Note: 1. Full page size is 21x28cm with format of .pdf or 56 Fiscal Regimes: It’s Not Just Costs That Drive 3FTFSWPJS&WBMVBUJPO4ZTUFN 3&4 NJOJNJ[FTZPVSSJTLXIFOUFTUJOHBOE .jpg and resolution of 300 dpi. LNG Prices TBNQMJOHJOIJHIFOEFYQMPSBUJPOXFMMT DBSCPOBUFSFTFSWPJST PSDIBMMFOHJOH 2. Article will be printed in Color only; paid article 64 Shrimp Boil Party 2013 TBNQMJOHDPOEJUJPOT*UTTMJNEFTJHOSFEVDFTSJTLTPGTUJDLJOHPSUPPMMPTT will also be displayed on our website, with the %VBMRVBSU[HBVHFBOEEVBMçPXMJOFTGVSUIFSFOTVSFSFMJBCJMJUZ)JHITQFDJæDBUJPO same duration. 69 SPE Java Scholarship 2013-2014 TBNQMFCPUUMFTQSPUFDUTBNQMFJOUFHSJUZsFWFOJOIJHI)24FOWJSPONFOUT For all advertising enquiries, please contact: 73 UPN Student Chapter (FUUIFEBUBZPVOFFEBUBQSFEJDUBCMFDPTUXJUIUIF8FBUIFSGPSE3&4TZTUFN 8FBMTPPGGFSEBUBBOBMZTJTBOEJOUFSQSFUBUJPOTFSWJDFTUPIFMQZPVNBYJNJ[FUIF Atria Lesmana 78 SPE Asia Pacific Events & Courses Schlumberger WBMVFPGZPVSNFBTVSFNFOUT 82 Board of Directors 2012-2014 Email: [email protected] Learn more at weatherford.com Mega 42nd Floor Wisma Mulia Section Officer Jl. Gatot Subroto No. 42 Email: [email protected] Jakarta 12710 [email protected] Tel: (62-21) 2942-8222 Ext.253 E-mail: [email protected]

Formation Evaluation | Well Construction | Completion | Production

Minimize risk in high-value wells. High-value wells hold the promise of great returns—or the potential for TJHOJæDBOUMPTTFT%BUBRVBMJUZDBONBLFUIFEJGGFSFODF5IF8FBUIFSGPSE 3FTFSWPJS&WBMVBUJPO4ZTUFN 3&4 NJOJNJ[FTZPVSSJTLXIFOUFTUJOHBOE TBNQMJOHJOIJHIFOEFYQMPSBUJPOXFMMT DBSCPOBUFSFTFSWPJST PSDIBMMFOHJOH TBNQMJOHDPOEJUJPOT*UTTMJNEFTJHOSFEVDFTSJTLTPGTUJDLJOHPSUPPMMPTT %VBMRVBSU[HBVHFBOEEVBMçPXMJOFTGVSUIFSFOTVSFSFMJBCJMJUZ)JHITQFDJæDBUJPO

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Formation Evaluation | Well Construction | Completion | Production

these small finds be utilized and economically fish fry, and Kyle’s special Paella. Steve Caron exploited? Read GT Kryo’s article on monetizing and his team were responsible for the event. marginal and stranded gas, Sengkang’s modular Unfortunately for our Section, Steve is moving mini LNG development and Cluster LNG to Sumatra but hopefully will continue to make technology stories as you may be inspired on contribution to SPE. We thank and appreciate how small to medium size gas discoveries can Steve for his tremendous contribution to our still be monetized. Both Roesmaladi and Maswar Section. Good luck Steve in your new post. Makmur are prominent figures in the gas industry and LNG in Indonesia and perhaps they foresee We have gone through the selection process that mini LNG is the best way to commercialize for the scholarship recipients from the 8 student the many small gas discoveries. LNG is chapters during the month of November- perhaps a solution to connect gas sources and December 2013, and the recipients of this year’s markets where pipeline and other supporting SPE Java Scholarship program are listed in this infrastructure are lacking. Stewart Elliott has Newsletter. Thanks to Teddy Komaroedin and successfully implemented the modular mid-scale team who took care of the selection process. LNG in other parts of the world and is convinced The scholarship program is conducted with the the same concept can be replicated in Indonesia cooperation and generous support from Kota ear fellow SPE members and readers, through his Sengkang LNG project. The journey Minyak and BP Indonesia. We thank our sponsors it’s a pleasure to present to you the first from finding gas to LNG development however, and congratulate the recipients. I hope it will help Dedition of the Newsletter of 2014. This can be a long and winding road as you might advance the education and help maintain the issue carries the theme of LNG. We are honored to remember in earlier Newsletter, Haposan high level student chapter activities. have Nanang Untung, the President Director and Napitupulu described the long and variety of CEO of PT Badak NGL as our executive interview processes as well as the many permits one In the last APOGCE, our student chapters won as he shares his really insightful journey in the has to endure in recent years carrying out the as the winner, first and second runner ups, world of LNG. We have many other prominent reserves replacement scenarios. namely ITB, Gajah Mada and UPN. They will be contributors that are related to the subject, from competing in yet another regional event to be the historical side, the present and the future There are many other factors needed to be held in Kuala Lumpur. We wish you all the best. of LNG in Indonesia, as well as LNG concepts considered by introducing LNG to Indonesia; We have a new team to take care of student and technologies. We have republished related learn more from Irfani’s article which covers the programs, they are Titis, Avida, Julianta and articles from past Newsletters as we thought they supply chain and vessels, bunkering aspects of Chalvin to ensure our student chapters get the would supplement and cover a wider spectrum of mini LNG. The newsletter is not all about mini most benefit from our support. the LNG story. LNG though; we have a major gas find that is yet to be developed as a novel and yet to be The next distinguished lecture series is entitled: Indonesia’s LNG industry is not the first but at proven floating LNG designed for the Abadi giant Selective Water-Reduction Systems: Where one stage we were the biggest, we were known gas field. When it becomes onstream, some of Have We Been and Where Are We Going? The as the largest exporter of LNG in the world. the LNG will be bound for domestic use, such as speaker is Larry Eoff from Halliburton Houston We pioneered the industry in a big way and the case of Tangguh LNG plant expansion while Technology Center in Texas. Don’t miss this SPE the industry was and perhaps still is a major the rest will be exported. The export will no doubt Distinguished Lecturer! It will be on Thursday, contributor to the state budget that fuels the compete with LNG from other countries fighting March 13, 2014 from 11:30 AM – 13:30 PM at the economic growth and development of the country. for the same traditional market. Developing LNG Energi Mega Persada Offices, 25th Floor Bakrie From the historical side, we feature stories from however takes time and costs are increasing Tower, Rasuna Epicentrum, Jakarta. Please Huffco/Vico, Total and Mobil as they were the which no doubt impact the project economics. The contact Geoff Thompson and Puspa Sari to find major gas producers that supplied gas to the comparison of fiscal terms between Australian out more. The last distinguished lecture we had liquefaction plants of Badak and Arun. The story and Mozambique LNG development is illustrated was a well-attended talk by Alfred William Eustes now is different however, as other countries have in last article of the LNG story. III from the Colorado School of Mines. It was found and developed huge reserves and took an interesting talk and discussion on drilling in advantage of the lucrative business, meanwhile On Section matters, some of you may Mars. Indonesia becomes both an exporter and participated in the special 25th silver anniversary importer of LNG. In a way we complete the cycle celebration of our Section’s famous Shrimp Boil We are finalizing our own website instead of and take advantage in the utilization of this clean party. It was a blast and everyone had a lot of fun. linking to the main SPE webpage which was source of energy to meet our growing domestic Thanks to Doug Slusher, the Santa Fe team, the our common practice in the past. Thanks to energy demand (see Nusantara Regas story). committee members and generous contribution Steve Broadmeadow and Atria Lesmana who from our sponsors. Your contribution goes to a are taking the lead on this effort. Lastly, I would There are multiplier effects in introducing LNG good cause, in the effort to advance Indonesian like to thank to the many people who contributed to indonesia’s energy mix, but is LNG the best Students. in the past as well as the current B&C which I solution to fulfill the energy shortage gap? Read really appreciate their contribution, in particular professor’s HL Ong’s article and find out his point Our Shrimp boil and the recent Fish Fry provides Thomas, Hasbi, Iwan, Peter and Mega. You may of view. Gas however, can and will always play a funding for the SPE Java Section scholarship have noticed we have some changes in our B&C crucial role as our population grows in the ever- program and student chapter activities to members. You are welcome to participate and we growing energy needs that surpasses our ability encourage students to showcase their academic always welcome new members. Thank you. to supply. We seem to find more gas than oil; and extracurricular talents. The Fish Fry event though not giants fields such as Arun, Badak, was well-attended despite of the rain; the Jakarta Bambang Istadi Nilam or Tunu but small to medium size. Can Chefs provided their authentic Louisiana-style SPE Java Section Chairman 2012-2014

4 SPE Java . Jan - Feb ‘14

Society of Petroleum Engineers Distinguished Lecturer 2013-14 Lecture Season

Thursday, 13 March 2014 11:30 AM – 13:30 PM Energi Mega Persada Offices 25th Floor Bakrie Tower, Rasuna Epicentrum, Jakarta

Selective Water-Reduction Systems: Where Have We Been and Where Are We Going?

Larry Eoff Halliburton

Abstract:

Selective water-reduction systems (also known as relative permeability modifiers or disproportionate permeability modifiers) with consistent, sustained performance have been pursued by the oil and gas industry for many years. This is understandable because of the ease associated with connecting to the wellhead, simply pumping a treatment, and watching water production decrease (and hopefully oil and gas production increase). While most systems reported in the literature have not experienced sustained usage, a few have experienced success. In recent years, these systems have begun to be incorporated into other areas, such as additives to fracturing fluids, diverters for acidizing treatments, and as leakoff- control agents. While all of these applications are not necessarily geared toward controlling water production, they have resulted in increased experience with the chemicals and increased acceptance of water-reduction applications. This presentation discusses the mechanisms of selective water-reduction systems, case histories for both water reduction and alternate applications, and how this class of compounds and their applications could potentially be improved for increased success in the future. The intended take home message from this talk is that selective systems DO work and are showing great promise for other oilfield operations.

Biography:

Larry Eoff is currently a chemist with Halliburton at the Houston Technology Center in Houston, Texas. He spent five years in Halliburton’s cement product development group, followed by two years with Aquaness Chemicals. After returning to Halliburton, he has spent fifteen years in the water control product development group and is currently the team lead for both the water control and acid groups. He holds a BS in chemistry from the University of Central Arkansas and a PhD in organic chemistry from the University of Arkansas. He has authored more than 30 papers and holds more than 60 US patents.

For information and reservation, please contact Mega at: [email protected] or [email protected]

5 SPE Java . Jan - Feb ‘14 Profile

Interview with Nanang Untung

6 SPE Java . Jan - Feb ‘14 Profile

Recently, Nanang received SPE in his office were able to accomplish the mission, three very much. for a very interesting and inspiring chat. came from Houston: 1 project manager, 1 business manager, 1 engineering manager, 1 I then continue with Train I. At that time Total SPE: Can you please tell us about process manager. These four people started said that they had huge reserves, but the your career? to hire, from secretary to draftsmen, looking competitor to this was apparently Tangguh. for the office, etc. Both parties promoted their reserves. The Actually my life journey has been captured Government decided to give the priority to for the Inspirational Book, compiled by my Within 6 months of the Tangguh. Tangguh was to be built to be online friends in ITB Class of 1977. I am very happy start, in 2001, but it was a time of buyers, no longer to share it again. I graduated from ITB in 1982, the sellers’ market. At that time the price condition majoring in Chemical Engineering. I was then was also not good and it was the first time accepted by PT Arun as a direct hire, where that in order to sell the gas we had to follow a I learnt many different aspects as a process tender process and we lost. It was blessing in engineer for l4 years. Significant exposure project disguise for me, because if the Train I were to happened in 1991, when I was sent to Long was proceed and start producing in 2001, it would term Development Program in Mobil Oil, already be a decline right away in 2002. The winner of since Arun had a close connection with completed, the bid, the Australian, had similar price or even Mobil. I followed the program and I got involved worse. Indeed gas market and price was very at Mobil and followed all of situational. It is true that, if we think of “what this as the representative ifs”, if Pertamina and BPMIGAS/SKKMigas of PT Arun seconded to the had a good transition, then we could maximize project. It opened my eyes that the value from the traditional buyers through with only four people we can make good price and indexation, which I think was it, as long as the system able to support, missing. There might perhaps be negotiating from the corporate side and the industry tea, that he had already begun probing some side. From three candidates, from Pertamina, traditional buyers but was taken over by Badak and Arun, I was the chosen one. It BPMIGAS that had eye on China back then. Research maybe because of my exposure to LNG is Development better and more complex. Apparently, with But actually there was a higher leverage Center, in Princeton, my involvement in that project, I had to move in Pertamina, which at that time not being New Jersey, for around one from direct hire of PT Arun to join Pertamina exercised, for selling to Korea and Japan. and half year. At the completion of my in 1996. They may be saturated market, but who knows studies at Princeton, I then went to Dallas if we had not tried; we did not get any rejection to develop optimization simulation of all the In the same year, I went directly to Houston from them. I was not involved in that marketing processes for the next six months, getting to exercise the joint operation with Exxon to effort, but I believe if Pertamina could penetrate involved in projects including Qatar LNG. develop Natuna D-Alpha, in particular on the Japanese market, then the price would be LNG side. We examined several options for better. But it was only hypothetical. Going back to Indonesia, I opted to become a building LNG Plant in Natuna Island. We also professional instead of choosing a managerial studied the gas processing, not for LNG but Back to my involvement in Train I, we tried track. The consequence of overseas instead for pipeline to JDA (Joint Development to maximize the local contractors at that assignment was, when I came back, I was only Area between Thailand and Malaysia). We time, or at the least had them in partnership a staff engineer while my subordinates had even made options for pipeline to Java and with a more experienced oversees EPCI become my managers. It turned out that being Arun among others. In 1998 after all the efforts companies. The winner for the EPCI was the a professional provided more flexibility in my and related expenses, the oil price crisis made Consortium between EKPT, the leading local career. When Mobil decided to proceed with Natuna not economical to develop, and finally EPC contractor, with Chiyoda, and Technip. the NSO offshore development project, they the project was frozen. EKPT also participated in building train G, F needed someone who has the understanding and H. We had worked also with Tripatra and of the process so they asked me to join the I came back to Indonesia, to either join the Rekayasa Industri. These three companies project. I was included in the team from Mobil Tangguh or Bontang Train H; I chose the latter. were actually ready and suitable company to in Jakarta to develop the project. At first, it was Eventually I joined Pak Yoga in processing build LNG plant. In the high value projects, rather complicated because among others we management team at Bontang Train H. For the as high as $ 60 bn and more, these local have to build by ourselves etc. We attempted first time I got involved in a very big project that companies would team up and be supported to maximize the surplus capacity from the had a chance to be completed. My previous by world class EPC contractors such as LNG plant. At that time after the concept was NSO project was also completed, but my Kellog, TQC, Chiyoda, Technip, etc. This approved, I went back to Houston for making involvement was limited to FEED stage, while setup was intentionally designed to ensure the front end design with Mobil engineers. For the Natuna project was not accomplished. The technological transfer. We expected the global me doing this front end design with them was Train H was well done, from the engineering players to team up with proper local partners an amazing experience. From Mobil there design, construction, commissioning, to the taking significant role, not with the brokers. were only four engineers involved, but they acceptance test. It was a project that I enjoyed As Pertamina at that time we still had the

7 SPE Java . Jan - Feb ‘14 Profile

freedom to do that, if now maybe it will be many different future events. This project Pertamina was the integrator for all. Now more difficult. is actually an upstream initiative, but rather since SKKMigas became one separated entity than making upstream company that will the liability will be different from Pertamina. In The “Karya” companies such Adhi Karya, Cipta make confusion - as the asset are not that of short, the issuance of new Oil and Gas Law Karya, etc were not suitable because they upstream. The funding will also not come from Migas was not ideal for LNG business. were only Civil Contractors, not in a complete PSC, as they shall not be cost recovered. The EPCI. They did not have proper skillsets and funding of this special vehicle will come from The focus of the new law is more to experiences. the Government. Before Pt Badak dies, we downstream. In my opinion the downstream have to make a new company ready. scheme could be running well only if the After the completion of Train I, Pertamina upstream dan downstream were with the discovered a very huge reserve in Donggi In 2011, Pertamina needed a Senior Vice same party or the same management. It could Senoro. Initially Donggi was estimated to President to oversee the Sub Gas Directorate happen only if there is a transactional prices contain around 21 TCF, plus Senoro which had and I was summoned; they said I am the man that arranged to where you want the profit to 6 TCF. As an LNG man I would imagine that in the right place. So, in the year 2011-2012, be given, even under the same one entity. But the project would be very huge, compared to for one and half year I managed there, direct there were SKKMigas, Mitsubishi, Pertamina Arun which had 14 TCF, and would potentially reporting to Bu Karen. This is the forerunner of and Medco who were not on the same page. change my career. With experiences Pertamina the present Gas Directorate. I see that I have The weakness of Indonesia is in conformity. gained from Arun, it was time to have our own background in projects, business development, The parties were also not in the same sector. LNG plant and business. having the knowledge for gas business and In the case of Shell and Petronas in Malaysia, many more. We have to run to catch up for the they were both the same parties in upstream Unfortunately, the reserves decline was quite whole business with many strategic plans. We and downstream. It therefore was easier to sever after further evaluation. Senoro from 6 have developed Arun as LNG, and now it is arrange the internal transactional pricing, as TCF to 2 TCF, while Donggi from 21 TCF to just time for Arun piped gas. Actually we intended they are the same entities. The existence of around 1 TCF. The project is still alive now, but make pipelines from Aceh to Java, and then SKKMigas also made the financing scheme it will be best to become mini LNG. They were the mini LNG in East of Indonesia, and other more difficult. However, I saluted them who planned as separate development, but now things. We saw that in the golden era we had could still run and manage the LNG business it is sensible to combine the two together. At to make the infrastructure, and maybe in the although in difficult situation like that. first there was rejection from Joint Operating future we no longer need to import LNG. Now Body of Pertamina and Medco, but it was we can see that we already have more gas than SPE: Can you elaborate more on the resolved. Afterward came the big discussion, oil. Gas will become something. Alhamdulilah Special Vehicle company project whether we brought it upstream scheme or in 2012 Pertamina established the Directorate you mentioned? downstream scheme? This became a long of Gas with Pak Ary as the Director. At that and interesting issue. time I was told to oversee PT Badak, since It is not really a subsidiary company of PT the position to manage there was vacant. So Badak NGL, but rather a safe boat after the In Pertamina, I moved from engineering to I came back to PT Badak continuing what we demise of PT Badak NGL when the reserves business development. I was at the Pertamina had dreamed in 2008. finished. Pertamina will make this boat and corporate team, then went to Upstream migrate the people to this company when the Directorate, before moved again to Pertamina SPE: Can you elaborate more on the time comes. It is now a kind of innovation, a EP. In 2008, I was appointed the General LNG Business in Pertamina? sister company to PT Badak. PT Badak will Manager of PT Badak. I had to handle 1300 start to decline; at the time the sister company employees with all the problems, operations, LNG in Pertamina, however, was in three will start to grow. Our hope is like that and we technical, financial, dealing with Labor Union, separate hands which made coordination try to make it happened. etc. I felt like l like a Pangkowilhan (red: A difficult, which was why the Marketing did Territorial Military Commander). I enjoyed not go forward smoothly. The upstream was SPE: We are now also a gas importer this because never before I had so many managed by BKKA, Pengolahan, and for country. Is our prestige fading away subordinates. I did many changes, in terms of commercial/marketing aspects overseen by now? awareness that PT Badak is a special project Perdagangan Dalam Negeri in Biro Umum. who will eventually cease to exist when the The integration was unbearably difficult. LNG Actually there are missing phases. When project is finished. The life time of the project value chain shall not be managed like this. Indonesia had the first phase with Bung depends on the reserve. The evidence is PT Unfortunately, after BPMIGAS/SKKMigas was Karno proclaiming Indonesia’s independence, Arun. I made them aware of how and what established, Pertamina could not manage the nobody really believed that Indonesia can we are planning to do in the future. If they are upstream gas anymore, adding the problems go on. The truth was that we were not really all gone, then our knowledge and reputation into the already difficult upstream integration. ready, reflected in the sentence inside the will also all be gone. Pertamina will suffer Entities like PT Badak and PT Arun were like proclamation mentioning “…the following will losses, Indonesia will too. We need to prepare headless chicken. It was never been and no be done carefully and in as soon as possible”. when the time comes by creating a special - longer Pertamina’s business since Pertamina That revolutionary spirit happened with a company running in the field of Operations only handled the Marketing/ Commercial/ LNG. In 1973 Indonesia was far from being and Maintenance - to capture the employees, Business Development aspects. This situation considered as LNG country by many. I learned skillsets, experiences, etc that gained over still exists until now. There were also difficulties from Bambang Pramono that the buyers did many years of operation, to be utilized for regarding liability etc because formerly not believe us; they regarded us as a bunch of

8 SPE Java . Jan - Feb ‘14 Profile amateur. In the world then there were only very expansion and expansion, selling and selling. but lacking of knowledge of risk and power few LNG countries: Algeria, Christmas Island As Indonesian we did not think that it should of investment, not to mention technological and Brunei. The prominent Exxon, Mobil, Arco have been used as capital, to expand our capability. We need to invest in knowledge and were not yet seen. There was only Shell. But foreign exchange. It became worse with the funding. Indonesian people presently want to with the determination of Pertamina at that presence of BPMIGAS/SKKMigas as the have benefits from natural resources but do time, we convinced the Japanes buyers, New strength of Pertamina was even shattered not want to sacrifice; Quite contrary to the time York bankers, and pretty much everybody else. after this separation of authority. That was the of proclamation of independence. We completed the first LNG project in around bad side, in the good side Pertamina became 4,5 years. Now maybe no other projects that more aware that the strength was very weak About the import of LNG, I do not think we can be done as fast at that. Starting from compared to previously perceived. We came have to be afraid of importing LNG. At the finding a well in 1971, we delivered the first to our realization a bit too late when we are end all will become commodity. In the world at gas in 1977, five years. We have world class already ath the low point and missing some present we have Qatar, Mozambique, Russia, and the best LNG industry in the world. phases. We are unable now to develop Natuna; US, Iran and many more. Plenty of gas. If we we only fond for selling not developing. imagine our reserve ten years from now, it will The problem was we did not take the advantage be not as much as what we have at present. to develop it further in our country. We had the In Malaysia, LNG 1, 2 and 3, along with time How about 50 years later and so on? In East wrong image that our country is very rich with Petronas’s profit getting better and bigger, Java they said there was flood of gas, but abundant resources that will never deplete. while Shell getting smaller. In Indonesian in 50 years from now what will it be? Do not The image was very wrong, but even until now LNG, it is almost the reverse. While we were think always in short term, for LNG it should many people think that Indonesian’s resources developing Arun train 1,2, and 3, we were be long term planning. I had been taught that will always be there. That is the difference still learning so our bargaining position was the nature of LNG is long term, and what the between Indonesia with China, Korea and very low. But after Train 4,5, 6 we were business is experiencing time is a shifting from Japan. We have not started thinking for the actually in much higher position. But because long term contract to commodities short time/ next 100 years, so our achievement had not Pertamina LNG was then divided into three spot, it means that our infrastructure has to been used to penetrate the market while we parts with upstream apart, we could not move be good. We have to prepare to pay more, or have Arun and Bontang. Once, 35% of the quicker. It was late when we realized this, as if the Government want it cheap be prepare revenue of Mobil globally came from Arun. I also learned this when I was in Business for the subsidy and the industry is able to pay When Qatar came to our place asking to learn Development in 2005-2006, after Arun starting much. So it is sad if we are always been told from us, we were still glorious. At that time we to decline. We should have planted the seeds that Indonesia is very rich in Gas and Oil. should had been said that: okay you will be for the new trees before the old trees getting taught but you should bring us along in your older and die. Unfortunately also the system in SPE: What is your recipe for business, as was done by Mobil Oil. But we Indonesia getting more chaotic with the small success? were missing that golden opportunity. players which tried to compete with Pertamina, that may or may not promote competition but Actually it is passion. Passion means that In 1977 after Pertamina was bankrupt, the certainly will weaken Pertamina. If we do the we enjoy our job and willing to learn, to see. LNG came along as a gift, something shiny Indonesians competition abroad it will be very Never refused a job, because it will always be and glittering which changed the image of good, but this was with our own friends inside a potential for our development. Even when Pertamina. Pertamina indeed had already the country like local government, local brokers, it is outside our normal job, we need to work fallen at that time, but we only satisfied with etc. They often tried to be oil and gas player, it out. If we have the willingness to thrive, we

9 SPE Java . Jan - Feb ‘14 Profile

have the deep understanding of our job, we Javanese culture, which is NITENI (listening), to make our life complete. I am very lucky are serious of what was given to us, it will NIROKE (imitating), NAMBAHI (improving). and very grateful to my wife, Esniar, who has make us as a trusted person to be given a We always have to be able to see many sacrificed a lot to leave her career at PT Arun higher responsibility. A person who is always important things even outside of our business. and accompany me in all of my assignments, complaining when given a job, but does not Are there things that we can take as example: in Indonesia and in US. deliver well, will not go forward. The second the spirit, the creativity, or the business, and aspect for success is opportunity. At that time so on? After that, is there anything that we In every assignment I always bring my family, the opportunities are more abundant and can improve? One small example was when including my two sons Yoni and Yanda. easier compared with now. Opportunities I was GM Pt Badak in Bontang. I saw that the Another happiness we felt was when my only should be accompanied with readiness for grass in the golf ranges is prettier and more daughter, Nena, was born in Dallas US. Her making us going forward. With our readiness manageable, hence I replaced the grass in grandparents came far away from Indonesia then the opportunities can bring us to success. the office compound with the grass from golf to witness that moment. That was the God Somebody with high level of readiness but not course. It was prettier, and we did not have gift to me and in particular to my wife for her getting any opportunities will be nothing, the to hire a person to cut off the grass more dedication to her husband and family. I was other way round will have no result either. For regularly again. I told my friends that in this also grateful that in the middle of my busy instance,the opportunity as the Senior Vice established world, in years of 2000s, lots of assignment, we were able to go for Hajj from President of Gas never occurred in my mind, things have been formulated and done in other Houston in 1997. but I keep on sharpen myself doing my work places by other players. We just have to be Nowadays, I find that I spend some relaxing the best that I can with an open minde. As the smartly doing NITENI, NIROKE, NAMBAHI. time getting better in golfing, the game where result, when there were the fit and proper test We work in service industry, in Oil and Gas, precisions, mental strength, and ability to beat I was chosen. not in Research. yourself are all that counts. However, most of my time now are dedicated to Indonesia oil I never imagine that I will be a SVP of Gas, SPE: Can you tell us more about and gas, in particular LNG. and going back here with PT Badak will be a your family? What do you do outside way of my career path. I believe that this job is of work? SPE thanks Nanang Untung for his time and not a scientist project. I always tell my friends inspiring chat, and we wish him successful to “Keep It Simple” with the formula of 3 N from I feel that the role of family is very important endeavors in Indonesia oil and gas.

From left to right: Hasbi Lubis, Nanang Untung & Bambang Istadi

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11 SPE Java . Jan - Feb ‘14 AN INDONESIAN INVENTION LINKING LNG PRICE

TO OIL PRICE Abdul Qoyum Tjandranegara n 1972, Indonesia geared up to start its fuel, and a substitute and complementary to Japanese buyers, instead of the US. The first LNG export, with the US market as product to crude. So I put forward an idea oil-linked gas price had risen to become US$ Ithe first identified destination. I was a to peg LNG price to crude price. The idea 2.0/mmbtu. member of the negotiation team, which was was initially rejected, and I was removed from lead directly by Ibnu Sutowo, the founder the team. But when the crude price increased A quick calculation shows, in twenty-five and then President Director of Pertamina from $ 1.60/bbl to $ 2.80/bbl in only three years of LNG sales, the fixed-price approach and Wijarso as Executive Project Leader. months, Ibnu Sutowo began to realize the would have brought 30 billion to Indonesia, Price was provisionally agreed at US$ 0.60 benefit of my idea. Finally, I was asked to re- whilst pegging to crude brought $ 140 billion. /mmbtu, with a 3%annual escalation. Our join the negotiation team. Subsequently, the team was jubilant with the four-fold increase gas price was pegged at 90% of crude price. My role in gaining this US$110 billion from the buyer’s initial offering of $ 0.15/ of additional income to Indonesia led to mmbtu, but this completely ignored oil price, This formula principle has been followed by the Bintang Jasa Mahaputra Mahaputra which had already shown its own volatility. I gas suppliers all over the world up to this award, which entitles me to be buried at the suggested abandoning this pricing concept, day. distinguished National Heroes’ Cemetery in because it did not recognise that LNG was not Kalibata, South Jakarta. a commodity, but a scarce resource of fossil In 1976, LNG export began from Bontang, but

echnological developments in plant production capacity resulted LNG in improved and increased T shore" LNG Plant, new technologies have created Floating LNG (F-LNG), which allows for offshore capacity. Initially production capacity was approximately 1 mtpa, has reached 7.8 mtpa, liquefaction (e.g. one being planned for thePROCESS giant Abadi gas field in Masela). and the capacities of the various process gas compressors used in the plant are also increasing. At the same time, there is also growing interest in the development of small and mid-sized LNG plants as a means of monetizing stranded gas fields.

At an LNG plant, the liquid components (condensate) are removed from the natural gas that was produced from the gas field. The natural gas then passes through acid gas (hydrogen sulfide, carbon dioxide) removal equipment, mercury removal equipment, dehydration equipment, and NGL removal equipment, and is then liquefied by liquefaction equipment where its volume is reduced by a factor of 600. Afterwards, the natural gas is stored in an LNG tank. Recently, in addition to the conventional “On-shore” LNG Plant, new technologies have created Floating LNG (F-LNG), which allows for offshore liquefaction (e.g. one being planned for the giant Abadi gas field in Masela). LNG process diagram is based on APCI C3-MR process.

12 SPE Java . Jan - Feb ‘14 THE STORY OF govern the new LNG business and continues VICOplant remains one of the largest plants in the to govern Bontang to this day. world but is now hungry for gas. Many are exploring for gas in East Kalimantan, spending Pertamina with the support of VICO and its hundreds of millions of dollars, in hopes of partners, then executed a 20 year LNG sales feeding their gas to Bontang and continuing contract in December 1973 with Japan and the growing of Indonesia’s economy. built what is now the mighty Bontang LNG Plant. Indonesia’s first shipment of LNG VICO pioneered the LNG business in Indonesia sailed to Japan in August 1977, only 5.5 years and is now on the brink of revolutionizing the after Badak field was discovered in Sanga industry once again with Coal Bed Methane Sanga. A world record that will probably (CBM) development. The company continues never been beaten. VICO and its partners, to renew itself and is very excited about its with the strong support of the Government future. VICO has been at the forefront of the of Indonesia, pioneered the LNG business in Indonesian LNG industry for 40 years with Badak Plant Indonesia. The contracts and Badak’s gas the development of Bontang LNG plant With reserves underwrote the initial investments in the signing of the Sanga Sanga CBM PSC on or almost forty years, VICO Indonesia the Bontang. LNG plant, facilitating the first 25 November 2009 between BPMIGAS and has been providing clean energy export of LNG to Japan in August 1977. From Sanga Sanga Contractor, we begin the next Ffor Indonesia. VICO or at that time East Kalimantan LNG ships head northward chapter in VICO’s history. The Sanga Sanga HUFFCO has been providing clean energy for to Japan, a distance of some 2,400 nautical contract area has now been dIvided into two Indonesia. VICO Indonesia was searching for miles from Bontang. PSC’s covering the same area. oil in the Kutai Basin of the Mahakam River Delta in East Kalimantan when they made a The Japanese uses the LNG, a clean energy After the PSC award in 2009, VICO has huge discovery. It was not, however, the oil for their power generation and natural gas undertaken a large work program to field they were hoping for. Instead it was a to homes, and industries. In the decades to materialize its vision for CBM. One of the first huge deposit of Natural Gas. come, other producers followed VICO’s lead milestones was the CBM gas to electricity - Total Indonesie of France and Union Oil program when VICO Indonesia delivered all In January 1968 Texas Oilman Roy M. (now Chevron). VICO built and operates the gas production from CBM wells to the PLN’s Huffington visited Indonesia where he met Dr. East Kalimantan pipeline system supplying generator sets, or known as the 1st CBM to Ibnu Sutowo to talk about exploration areas in Bontang LNG Plant and the petrochemical Electricity Project in Indonesia. As committed Indonesia. In August of that year, HUFFCO plants from all PSCs, and VICO is the gas by President and CEO, Gunther Newcombe, signed the 30 year Production Sharing coordinator for all of East Kalimantan. VICO continues to develop all gaseous Contract for the Economic Development hydrocarbons in Sanga Sanga, and hopes to of Natural Gas, including all gaseous Indonesia quickly grew from zero to number revitalize East Kalimantan’s LNG industry. hydrocarbons, and other petroleum with one in the LNG Business for many years. The Pertamina led by General Dr. Ibnu Sutowo, LNG Business is one of the largest contributors By: VICO General Affairs & Communication which was the first PSC calling for onshore to Indonesia’s economy. The Bontang plant Team (February 2014) work in East Kalimantan and the only one is owned by the Indonesian Government and specifying explorations for “natural gas and is operated by other petroleum”. PT Badak NGL Under the POA. Exploration activities began soon thereafter. VICO holds a In February 1972 the giant Badak Field was 20% share in discovered in Sanga Sanga establishing one PT Badak NGL of the most important milestones in the history and provides of energy in Indonesia. Badak Gas reserves c o m m e r c i a l were located in the middle of the jungle of East & technical Kalimantan, with the nearest market more support. With than a thousand miles away. But Huffington, eight LNG trains and Dr. Ibnu Sutowo have a vision: to liquefy and a production the natural gas and ship the resultant LNG capacity in to Japan and other markets. This vision was excess of 20 realized in 1973 when Huffington and Ibnu million tons Sutowo signed a Principle Agreement, now per year, the known as the Bontang POA, to build and Bontang LNG Bontang

13 SPE Java . Jan - Feb ‘14 terminal in swamp area, extension or new platform in offshore area, processing and compression facilities are essentialtosupportthefieldproduction.Alloftheseactivitieshavebeenthesignificantkeysinthepermanent fightagainstfieldproductiondeclineinMahakamPSC.

FutureChallenges

Theexistenceofmultilayeredgasandoilreservoirswithrathercomplexcharacteristicsareindeedrequiringthe bestreservoirmanagementsystem,mostupdatedsciencesandinnovativetechnologyinalldomainsandinevery stepofwork,fromexplorationuntilfielddevelopmentandproduction.

Thedevelopmentofthefieldshasbeendonetroughphaseddevelopment,inwhichplanningandoperationhave beencontinuouslyimproved.OnemayseeclearlythatthecompetencyinmanagingthismultiͲfieldsdevelopment hasbeenacquiredtroughyearsofexperienceaswellasdedicatedworksoftheteammember.

Since the initial production of Bekapai in 1974, TOTAL has been drilling more than 2000 wells in Mahakam operation.Wellspacingisnowgettingcloser;thefieldisnowgettingmature.Newwellsstakearenowlowerthan inprevioustime,reservoirpressureisweakening,waterisrisingandmorewellinterventionsarerequiredthekeep the wells alive. The challenge is now to find an innovative solution to cope these challenges. Among these solutions are: efficient andwell maintaineddatamanagement,integratedand updatedreservoir model, lighter well architecture, innovative completion techniques, intensive perforation jobs, sand control application, producingwatermanagementandwatershutoff(mechanicalandchemical).

Mahakam: Toovercomealloftheseoperationchallenges,acontinuoustechnicalcompetencybuildinghasbeencarriedoutin TEPI geosciences team. In the first 5 years of employment, one has to pass their Geosciences Passport. Upon Continuouscompletion, Improvementhenvariousindividualdevelopmentstcould betailored:furtherfundamentaldevelopmentviamaster program, international assignment in HQ and or in other affiliate. These systematic developments result in a in Managingstrong, skillfullyChandaexperiencedllengingworkingstructurein TEPI. All these elements are required to fully develop the hydrocarbon in place in Mahakam area at the optimum, Fieldssustainable Dandevelopmeneconomicalway. t Noor Syarifuddin, VP Geosciences & Reservoir TOTAL E&P Indonesie Figure1.GenerallocationofMahakamFields

Introduction Upper Miocene. The pay zone interval of fields lying between 600 to 5000m subsea. The OTAL E&P Indonésie (TEPI) has reservoirs are composed of series of fluvial been the Operator of the Mahakam to deltaic deposits from the ancient Mahakam TPSC since 1970 in partnership with delta. INPEX. The block is located in the transition and offshore of Mahakam Delta area of East The hydrocarbon accumulations are situated Kalimantan. mainly along three elongated NNE‐SSW structural axis. The westernmost axis is the The exploration activities were started since Internal Axis, there are Handil, Tambora, 1968 with intensive seismic campaign and Nilam and Badak structures (the latest two exploration drilling. The first discovery was fields are operated by other contractor). The made only after drilling six dry holes. The Median Axis includes Bekapai, Peciko and first discovered field is Bekapai Oil field in Tunu, with the main pay reservoirs are found 1972. Since then, with the application of a in early Upper Miocene section. The External comprehensive exploration strategy as well Axis, located further offshore, is grouping Sisi as the latest available technology, TOTAL and Nubi fields. successfully discovered various fields in the block: Handil (1974), Tambora (1974), Figure 1. General location of Mahakam Fields Meanwhile, the South Mahakam field is Jumelai (1975), Tunu (1977), Peciko (1983), located in the southern part of Kutei Basin, the Sisi (1986), Jempang (1990), Nubi (1992), structure is mainly controlled by Sepinggan Metulang (1998), Stupa (1996), Mandu (2007). To manage this high level of activity, TOTAL fault system with WNW-ESE trend. The fields Bekapai was the first field being developed in is benefiting of its more than 40 years include Stupa, Mandu, Jempang, Metulang 1974. Since then, number of fields have been experiences in the area. There are 9 drilling and Jumelai. further discovered and eventually developed: rigs that are in operation to drill around 100 Handil (oil+gas), Tambora (oil/gas), Tunu wells per year. Nearly 800 marine-fleets have The reservoirs comprise three main facies: (gas), Peciko (gas), Sisi-Nubi (gas) and to be managed to support the operation. There fluvial channel point bars, delta plain new gas fields recently put on production in are around 47 millions man hours per year. distributary channel side bars (both known South Mahakam area (Stupa, Mandu). More The Operator is also keep maintaining a long- as channel facies) and delta front mouth bars than 16.8 Tcf of gas and 1.5 Bbls of oil have term position through major investments at 2.5 (bar facies). The fluvial channel facies is quite been produced in the last 39 years. Today the billion US$ per year as well as through wide and it has very good connectivity. While Mahakam PSC is producing around 1.7 Bscf/d implementations of leading-edge technology the distributary channel (side bar) is much gas as well as 67 kbbl/d of oil and condensate and innovation. narrower, with more elongated geometry. The from over 800 producing wells, out of 2000 geometry of bar is assumed to be triangular wells drilled in Mahakam area. Geological Setting of Mahakam shape and a relatively thin individual bodies. Area However they are often found as stacks Today, Mahakam PSC gas production is one of several bodies and have an important of the largest in Indonesia and contributes The Kutei Basin is one of the most prolific region thickness. approximately one-third of Indonesia gas for both oil and gas in Indonesia. Researchers production. Mahakam PSC is supplying up estimation on recoverable reserves is Fluvial & distributary channel facies are major to 80% of Bontang LNG Plant gas input. approximately 3 billion barrels of oil and 30 reservoirs in Handil, Tambora, Bekapai and Meanwhile, an important part of the gas Tcf of gas. Hydrocarbon was accumulated Sisi Nubi. Tunu field is mainly composed by production is also dedicated to fulfill growing and hence production is predominantly from series of distributary channel and mouth bars domestic needs in the region via pipe lines as thousand sand reservoirs aged Middle to facies, meanwhile Peciko field is more mouth well as shipped as LNG to RFSU Java. bars facies dominated.

14 SPE Java . Jan - Feb ‘14 Figure2.GeneralgeologicalcrossͲsectionofMahakam and evaluate the scattered gas reservoirs present in a limited extension. Various seismic reservoir characterization methodologies (sub-stack evaluation, inversion, AVO) have been developed, improved & used for better evaluation of subsurface condition. One of the latest important outcomes is the successful evaluation of shallow gas occurrences in Tunu. The shallow reservoir production pilot was initiated in 2010. Following the success of this Figure2.GeneralgeologicalcrossͲsectionofMahakampilot and after further improvement, the shallow reservoirs are now being fully developed and contribute importantly to the overall gas production. This innovative effort has been Figure 2. General geological cross-section of Mahakam Figure3.Extensiveuseofseismicdataforwelltargetdefinitionandquantitativeevaluation able to convert the used to be operational data (pressure and production data). The hazard into profitable gas production. Reservoir Characterization integrated workflow allows constant update and efficient quality check of an enormous Field Development Strategy The main challenge in reservoir identification amount of data. is related to its thickness, most of them being Due to the reservoir characteristics, field below the resolution of seismic data. Moreover, Meanwhile, since the past 5 years, new developments have been done in various these reservoirs are found randomly both seismic acquisition and processing have phases. New part of the field has been brought laterally and vertically. To be able to model and also been done intensively. This campaign on stream progressively to adapt (1) the predict the individual sand body will require has continuously brought very significant improvement of the understanding of reservoir the full integration of various subsurface impact on the understanding of existing heterogeneity and distribution, (2) the results informations. and additional hydrocarbon accumulation. of the continues delineation program and TheFigure 3D seismic3.Extensive is useduse toof locate,seismic visualizedatafor well(3)target the improvementdefinitionand of quantitative new and innovativeevaluation During the operation, TOTAL has been acquiring thousands kilometer of well logging, thousands pack of drill cutting, hundreds meter of core as well as hundreds of fluid sample. All of these important data have been cataloged, stored and capitalized for better understanding the characteristics of Mahakam reservoirs. Further, geological outcrops in onshore area and modern Mahakam Delta have also been used intensively as analogue and calibration during the subsurface reservoir modeling.

Another unique characteristic of Mahakam reservoirs are also in the fluid distribution. In a single well there could be hundred of reservoirs with alternating fluid content of gas, oil or water. This has been further complicated by thin reservoir nature that often cannot be properly characterized by wireline logging. Comprehensive method in fluid typing has also need to be developed.

The reservoir models, both static and dynamic, have been updated regularly by integrating the latest well results as well as feedback from field behavior. Annually, there are nearly 100 new wells drilled and more than 10,000 well interventions done. The models comprise thousands channel and mouth bar reservoir and incorporate the sedimentological concept, stratigraphic framework, Reservoir Pressure Unit, fluid contacts and integration of dynamic Figure 3. Extensive use of seismic data for well target definition and quantitative evaluation

15 SPE Java . Jan - Feb ‘14 Figure4.Continouswellborearchitectureoptimization development has been acquired trough years of experience as well as dedicated works of the team member.

Since the initial production of Bekapai in 1974, TOTAL has been drilling more than 2000 wells in Mahakam operation. Well spacing is now getting closer; the fields are now getting mature. New wells stake are now lower than in previous time, reservoir pressure is weakening, water is rising and more well interventions are required to keep the wells alive. The challenge is now to find an innovative solution Figure4.Continouswellborearchitectureoptimization Figure 4. Continous wellbore architecture optimization to cope with these challenges. Among these Figure 5. Various innovative technology applications in Mahakam Operations: (a) Capillary String for gassolutionswell are: efficient and well maintained dewatering,technology. (b) Gas Lift macaroni for artificial gas lift,or remote(c) Sand gathering Consolidation terminal using in Resinswamp to area,mitigate datasand management, integrated and updated production,(d)MultiͲZoneGravelPacktopreventsandproductioninunconsolidatedreservoirs. extension or new platform in offshore area, reservoir model, lighter well architecture, Over time, the field development has become processing and compression facilities are innovative completion techniques, intensive progressively industrialized. A strong increase essential to support the field production. All of perforation jobs, sand control application, in the number of development wells, as the these activities have been the significant keys producing water management and water shut well spacing reduced, are implemented with in the permanent fight against field production off (mechanical and chemical). continuous well design optimization to further decline in Mahakam PSC. reduce its cost. These include the application To overcome all of these operation challenges, of lighter well architecture, efficient logging Future Challenges a continuous technical competency building has operation, rig less perforation as well as latest been carried out in TEPI geosciences team. In well completion techniques such as multi The existence of multilayered gas and oil the first 5 years of employment, one has to pass zones gravel pack and sand consolidation. reservoirs with rather complex characteristics their Geosciences Passport. Upon completion, are indeed requiring the best reservoir then various individual developments could be There are more than a thousand production management system, most updated sciences tailored: further fundamental development via wells from various fields in Mahakam PSC. and innovative technology in all domains and master program, international assignment in Intensive well servicing jobs, systematic data in every step of work, from exploration until HQ and or in other affiliate. These systematic acquisition and production monitoring (regular field development and production. developments result in a strong, skillful and PLT, Caliper log, Pulse Neutron logging/RST) experienced working structure in TEPI. are needed to maintain well productivity. The development of the fields has been done Injection of surfactant with capillary strings trough phased development, in which planning All these elements are required to fully hasFigure been 5. recently Various industrialized innovative to improve technology and operation applications have beenin Mahakam continuously Operations: develop and (a)produce Capillary the hydrocarbon String in for place gas well waterdewatering, lifting and the(b) well Gas eruptive. Lift Moremacaroni and improved.for artificial One may gas see lift, clearly (c) Sand that the Consolidation in Mahakam area using at the Resinoptimum, to sustainable mitigate sand moreproduction, complex surface(d)Multi facilities:ͲZone extensionGravel Packcompetencytoprevent in managingsandproduction this multi‐fieldsinunconsolidated and economical way.reservoirs.

Figure 5. Various innovative technology applications in Mahakam Operations: (a) Capillary String for gas well dewatering, (b) Gas Lift macaroni for artificial gas lift, (c) Sand Consolidation using Resin to mitigate sand production, (d) Multi‐Zone Gravel Pack to prevent sand production in unconsolidated reservoirs.

16 SPE Java . Jan - Feb ‘14

Aceh Operations Mature Field Management: Arun Gas Field and North Sumatera Offshore (NSO) aceh Operations Mature Field Management: Arun Gas Field and North Sumatera Offshore (NSO)

Hanifatu Avida, Operations Technical, ExxonMobil Oil Indonesia Hanifatu Avida, Operations Technical, ExxonMobil Oil Indonesia Introduction of this massive resource in October 1971 by capacity of 3,500 MMSCFD with 4 well he Aceh Production Operations (APO) the drilling and testing of the Arun-1 discovery clusters and production trains. Each cluster includes three gas production fields well spawned the birth of the Indonesian LNG originally consisted ofIntroduction 20-21 production wells Toperated by ExxonMobil, consisting industry. Since then, Arun has been a valuable with gas separation,The test-separator Aceh Production train, Operations (APO) includes three gas production fields operated by ExxonMobil, consisting of the Arun, South Lhok Sukon (SLS), and resource that has been carefully developed dehydration, and compressionof the Arun, facilities. South As Lhok Sukon (SLS), and North Sumatera Offshore (NSO) fields. In this role, ExxonMobil serves North Sumatera Offshore (NSO) fields. In this and nurtured to maximize its potential. Field originally designed,as Arun Production wellstream gas Sharing Contractor (PSC) to the Indonesian Oil and Gas Upstream Regulatory Body, SATUAN Acehrole, ExxonMobil Operations serves as Production Mature Sharing Field performanceManagement: has been Arun excellent Gas and Field the undergoesand North a 3-phase separation and then Contractor (PSC) to the Indonesian Oil and application of the latest petroleum technologies propane-refrigeratedKERJA dehydration. KHUSUS The dry gas KEGIATAN USAHA HULU MINYAK DAN GAS BUMI (hereinafter called “SKKMIGAS”). The SumateraGas Upstream Offshore Regulatory Body, (NSO) SATUAN has extended field life. Arun remains a great and separated condensatelocation are then of deliveredeach field is shown in Figure 1.This article describes different strategies in maintaining profitability of KERJA KHUSUS KEGIATAN USAHA HULU success story with excellent recovery and high to a central gatheringtwo and mature metering assets, station namely the Arun and NSO fields. The primary challenge in Arun is to achieve flat to declining MINYAK DAN GAS BUMI (hereinafter called well productivity. Arun has now matured and called Point-A, beforeexpense transfer to the targets PT Arun with continuously declining production and excess installed equipment capacity. The main “SKKMIGAS”). The location of each field this article presents the challenges associated Natural Gas Liquefaction Plant for downstream is shown in Figure 1.This article describes with managing this mature asset to meet end-processing. Producedchallenge water in disposal NSO is to optimize gas production while managing water breakthrough from a strong water-drive different strategies in maintaining profitability market commitments. was initially via surfacereservoir. discharge. Water re- of two mature assets, namely the Arun and injection wells were implemented for disposal NSO fields. The primary challenge in Arun is Arun was developed from 4 clusters, and a few years after startup. The maximum to achieve flat to decliningHanifatu expense Avida, Operations targets total Technical, of 118 wells ExxonMobil have been Oildrilled, Indonesia most of gas production rate of 3,500 MMSCFD with continuously declining production and them deviated holes. The initial reservoir was achieved in 1995. Peak condensate excess installed equipment capacity. The main pressure was 7115 psi and the temperature production of 130,000 BPD was achieved challengeIntroduction in NSO is to optimize gas production 351F at a datum depth of 10,050 ft. The field in 1989. A portion of the gas was re-injected Thewhile Aceh managing Production water Operations breakthrough (APO) from includes a is approximately three gas production18.5 km long fields and 5operated km wide by priorExxonMobil, to year 1998consisting to maximize condensate of the Arun, South Lhok Sukon (SLS), and North Sumatera Offshore (NSO) fields. In this role, ExxonMobil serves asstrong Production water-drive Sharing reservoir. Contractor (PSC) to and the Indonesiancovers approximately Oil and 23,240Gas Upstream acres. The Regulatory production. Body, The SATUAN maximum re-injection rate KERJA KHUSUS KEGIATAN USAHA HULUaverage MINYAK thickness DAN of GAS the Arun BUMI limestone (hereinafter is 495 calledof 900 “SKKMIGAS”). MMSCFD occurred The in 1995, using locationArun Field of each Development field is shown in Figure 1.Thisft, and article the formationdescribes has different an average strategies porosity in maintaininga network profitability of 11 injection of wells distributed twoThe mature Arun gas assets, field namely is a giant the hydrocarbonArun and NSO of fields.16.1%, The with primarya low connate challenge water in saturation Arun is to achieveover the flat4 clusters. to declining After 1998, some of the expenseresource targets in Indonesia with continuously and has declining been of production10.7%. and excess installed equipmentinjection capacity. wells The were main converted to production challengesupporting inLiquefied NSO isNatural to optimize Gas (LNG) gas sales production while managing water breakthrough fromwells a strong3. Liquids water-drive were extracted from the re- reservoir. to the Asian market since 1978. The discovery Surface facilities were designed for a peak injected gas using a field-based NGL plant, which operated from 1988 to 1998.

Arun reservoir is a reefal carbonate complex of Early to Middle Miocene age 5. The initial gas in place of 14.1 TCF Residual Hydrocarbon (RHC) gas. Currently more than 99% of the expected ultimate gas recovery has been produced. The unique combination of reservoir management, excellent reservoir quality, subsurface engineering technologies, surface facilities design and facilities modifications have contributed to Arun achieving such a high recovery factor.

After more than 30 years of operation, declining reservoir pressure in Arun have resulted in lost well capacities due to insufficient Figure 1 - APO Fields Location reservoir energy to lift condensed liquids out of wellbores. In addition to declining reservoir

Figure 1 - APO Fields Location pressure , Arun has also declined because of

Figure 1 - APO Fields Location

Arun Field Development 17 SPE Java .The Jan -Arun Feb ‘14 gas field is a giant hydrocarbon resource in Indonesia and has been supporting Liquefied Natural Gas Arun Field Development (LNG) sales to the Asian market since 1978. The discovery of this massive resource in October 1971 by the The Arun gas field is a giant hydrocarbon resource in Indonesia and has been supporting Liquefied Naturaldrilling Gas and testing of the Arun-1 discovery well spawned the birth of the Indonesian LNG industry. Since then, (LNG) sales to the Asian market since 1978. The discovery of this massive resource in October 1971 by the drilling and testing of the Arun-1 discovery well spawned the birth of the Indonesian LNG industry. SinceArun then, has been a valuable resource that has been carefully developed and nurtured to maximize its potential. Field Arun has been a valuable resource that has been carefully developed and nurtured to maximize its potential. Field 2 performance has been excellent and the application of the latest petroleum technologies has extended field life. Arun remains a great success story with excellent recovery and high well productivity. Arun has now matured and this article presents the challenges associated with managing this mature asset to meet market commitments.

Arun was developed from 4 clusters, and total of 118 wells have been drilled, most of them deviated holes. The initial reservoir pressure was 7115 psi and the temperature 351F at a datum depth of 10,050 ft. The field is approximately 18.5 km long and 5 km wide and covers approximately 23,240 acres. The average thickness of the Arun limestone is 495 ft, and the formation has an average porosity of 16.1%, with a low connate water saturation of 10.7%

Surface facilities were designed for a peak capacity of 3,500 MMSCFD with 4 well clusters and production trains. Each cluster originally consisted of 20-21 production wells with gas separation, test-separator train, dehydration, and compression facilities. As originally designed, Arun wellstream gas undergoes a 3-phase separation and then propane-refrigerated dehydration. The dry gas and separated condensate are then delivered to a central gathering and metering station called Point-A, before transfer to the PT Arun Natural Gas Liquefaction Plant for downstream end-processing. Produced water disposal was initially via surface discharge. Water re-injection wells were implemented for disposal a few years after startup. The maximum gas production rate of 3,500 MMSCFD was achieved in 1995. Peak condensate production of 130,000 BPD was achieved in 1989. A portion of the gas was re-injected prior to year 1998 to maximize condensate production. The maximum re-injection rate of 900 MMSCFD occurred in 1995, using a network of 11 injection wells distributed over the 4 clusters. After 1998, some of the injection wells were converted to production wells 3. Liquids were extracted from the re-injected gas using a field-based NGL plant, which operated from 1988 to 1998.

After more than 30 years of operation, declining reservoir pressure in Arun have resulted in lost well capacities due to insufficient reservoir energy to lift condensed liquids out of wellbores. In addition to declining reservoir pressure , Arun has also declined because of wellbore failures. Reservoir pressures at Arun have fallen from the initial 7115 psig to less than 300 psig currently as shown in Figure 2. As a result of declining pressures and other factors, Arun field currently produces less than 5% of its design capacity for both gas and liquids. Therefore, the majority of facilities have significant excess capacity.

Compressor and Dehydration Average Arun field Reservoir Pressure Upgrade 8,000 In the early years of production, the Arun Actual reservoir pressure was in excess of 7000 psig, 7,000 Simulation so there was no need for field compression. With declining pressure, booster compressors 6,000 were installed in 1997 in Cluster 2 and 4 to reduce wellhead pressures and maintain 5,000 production. Each installation consisted of 3 parallel compressor trains, with each train 4,000 having two compressor stages driven by a GE Frame-5 gas turbine. Only the high pressure 3,000 (HP) stage was needed initially; the LP stage was activated several years later as reservoir 2,000 pressure continued to decline. Propane-

Avergae Reservoir Pressure, psi based refrigeration systems were employed to 1,000 dehydrate the gas downstream of the booster compressors (HP dehydration). 0 1977 1979 1981 1983 1985 1987 1989 1991 1993 1995 1997 1999 2001 2003 2005 2007 2009 In 2000, a joint ExxonMobil Oil Indonesia Inc and ExxonMobil Production Company Central Figure 2 Average Arun Reservoir Pressure (1977-2009) Technology task force was commissioned to wellbore failures. Reservoir pressuresFigure at 2 Arun Average that Arun Arun Reservoirhad to be drilledPressure underbalanced (1977-2009) to evaluate alternative for reducing the operating have fallen from the initial 7115 psig to less prevent formation damage in a reservoir whre suction pressure to 50 psi. The most economic than 300 psig currently as shown in Figure 2. pressures had decreased substantially. Drilling option was to upgrade the existing propane As a result of declining pressures and other underbalanced at low pressures in a high dehydration system instead of installation of a factors, Arun field currently produces less temperature environment at depths exceeding new glycol dehydration plant. In conjunction than 5% of its design capacity for both gas 10,000 ft presents a formidable challenge. Also with the dehydration upgrade, the compressor and liquids. Therefore, the majority of facilities the reservoir pressure continues to decraese facilities were also re-evaluated. The task have significant excess capacity. by about 8 psi per month at current depletion force recommended the replacement of rates. Thus, decisions about when to drill and the low pressure compressor casing and Managing a Mature Arun Field the pace of drilling are essential in program the installation of larger wheels to increase Arun is a critical field for meeting LNG delivery. planning. throughput and reduce suction pressures to Much effort has been put into maintaining 50 psi for two compressors on Cluster IV and the production, managing the reservoir and The drilling program begin on 18 June 2002 one compressor on Cluster II. stemming the production decline. Several with the spudding of the first well and was subsurface engineering technologies have concluded on 6 Sept 2003 with the completion The dehydration project and compressor been applied in Arun field to extend facility life of final well. Eight wells have been drilled upgrades were completed in 2002.At by increasing gas production and condensate using a new optimized Big Bore well design. comparable suction and discharge pressures, recovery 4, such as: large-diameter wellbore The major innovations included th use of 10” the new compressor capacity is almost 75% completions, horizontal drilling through tubingless completion string to replace the old higher. The upgrades have reduced anticipated condensate-rich formations 5, and acid assembly of a 10” liner, 13-3/8” production reservoir abandonment pressure to 270-290 stimulation. Three major efforts are discussed packer and 9-5/8” floating seal assembly. The psi and also allow the early retirement of in this article: the new drill well program, the underbalanced drilling of Arun limestone is old compressor trains, which helps reduce compressor and dehydration upgrade project accomplished using a nitrogen-water mist as compressor fuel usage, turbine overhaul and the Arun clusters assets consolidation. drilling fluid. Directional profiles of the wells costs, operating and maintenance costs, and were kept below 25o to maximize wellbore emissions of carbon dioxide. New Drill Well Program stability. Wellbore failures made it imperative that Arun Clusters Assets Consolidation the failed wells be replaced by sidetracking As the results, seven wells were successfully With the end of Arun field life approaching, existing wells or by drilling new ones to supply produced and one well had to be re-drilled the logical approach to sustain profitability the required gas capacity. Seven Arun wells because of mechanical problems. The total with declining production is to consolidate were re-entered and sidetracked in 1997- initial rate was about 195 MMscf/D. These surface production facilities and eliminate 1999 to maintain productivity. However, wells are the last wells to be drilled in Arun, but excess capacity. Two of the most significant more wellbores were needed to meet supply the drilling technologies that were developed efforts were Arun Clusters Consolidation quantities and a program was initiated in and refined in Arun will continue to be used in Project (ACCP) in 2008-2009 and Arun Liquid 2000 to evaluate new wells. An important other locations. Handling Project (LHP) in 2010. factor in the decision making process was

18 SPE Java . Jan - Feb ‘14 4

1. Arun Cluster Consolidation Project (ACCP) The ACCP main objectives were to consolidate the booster compression systems in the Arun field from two stations (Cluster 2 and 4) into a single station in Cluster 4, and to consolidate four propane dehydration systems into a centralized system in Cluster 4. Major benefits of this project included: Deactivation of 1 GE-Frame 5 Gas Turbine Driven Booster Compressor – 6 MMSCFD fuel saving Deactivation of 1 GE-Frame 3 Gas Turbine Driven Power Generator – 3 MMSCFD fuel saving Reduction of annual base OPEX - $350K, including recertification, inspection, manpower and spare parts Intangible cost reduction – logistics, propane consumption.

The ACCP was executed in two phases. Phase 1 (2008) covered installation of 18” and 20” inter-cluster pipelines which served as the Cluster 2 booster compressor by-pass, while Phase 2 (2010) reconfigured the gas processing systems in Clusters 1, 2 and 3 to allow deactivation of the propane dehydration systems. Simplified process diagrams of ACCP Phases 1 and 2 are shown in Figure 3.

cooling and gravity separation. The objective of Cluster 1, 2 and 3 gas processing after ACCP is no longer to produce pipeline sales quality gas, but only to provide sufficient superheat to prevent water condensation in the inter-cluster pipelines.

The costs of ACCP phases 1 and 2 were $1.25M and $0.75M respectively, with a total of 6 days downtime required. The primary benefit from ACCP phase 1 was 6 MMSCFD of fuel savings. Phase 2 provided an additional 3 MMSCFD fuel savings, and also was critical to maintaining 5 pipeline integrity. On an overall Figure 3 - ACCP Project Schematic basis, the ACCP reduced the amount of Arun Figure 3 - ACCP Project Schematic 1. Arun Cluster Consolidation2. Liquid to Handlingcondensation Project in inter-cluster (LHP) pipelines that field active equipment by almost 60%, base Following the successful outcome of the ACCP, a similar concept was developed for liquid handling systems in ACCPProject phase (ACCP) 2 addressed the concerns theof gas Arun dehydration could Clusters. not beperformance Beforemitigated the by in corrosion LHP,Clusters each 1,inhibitor 2 clusterand and3 in inthe annual Arun absence was O&M of equipped by $350K, with and condensate-waterfuel consumption separation, the propane dehydration systems, which may lead to condensation in inter-cluster pipelines that could not be The ACCP main objectives were to consolidatecondensate maintenance transfer, and pigging. produced In the wa originalter treatment design, facilities.by 9 MMSCFD The LHP (Irani, deco 2004).mmissioned all of those facilities in mitigated by corrosion inhibitor and maintenance pigging. In the original design, the propane dehydration system condensedthe booster heavycompression fractions systems and water in the Cluster vapor Arun from 1 theand the propane 2 gasand stream thereby dehydration at consolidated sub-ambient system condensed condensate-water temperature (45F forseparation LP and treatment in Cluster 3 and 4. The dehydrationfield from two and stations 70F for (Cluster HP dehydration). 2 and 4) maininto The a benefit vaporheavy streamof thisfractions wasproject thenand was superheatedwater deactivation vapor fromin a of gas-gasthe oversized gas exchanger,2. condensate Liquid and Handling pumps, which Project eliminated (LHP) a process integrity threat. Below turndown limit, the condensate pumps vibrated excessively, resulting in small leaks at weld joints. thesingle liquids station were in routed Cluster to 4,a condensateand to consolidate / water separator.stream at sub-ambient temperature (45F for Following the successful outcome of the Each condensate pump consumes 690 HP electric power, the largest power consumers in Cluster 1, 2, and 3 Afterfour ACCP propane phase dehydration 2 commissioning, systems the intoafter LP aand ACCP HPLP phasedehydrationpropane 2 dehydration was and commissioned. 70F systemsfor HP dehydration). in Deactivation Clusters 1, 2ACCP, ofand two 3 a condensatewere similar concept pumps was enabled developed 15-20% for reduction of decommissioned,centralized system and in Cluster gas processing 4. Major benefits inArun those Clusters clustersThe vaporpower relied stream consumption. on ambient was then cooling In superheatedaddition and gravity to the in separation. condensateliquid handling The pumps, systems the LHPin the also Arun eliminated Clusters. several other objectiveof this project of Cluster included: 1, 2 and 3 gas processingtypes after of a equipment, ACCP gas-gas is noexchanger, including longer to produce and condensate-water the pipeline liquids sales were separators, qualityBefore gas, the producedbut LHP, each water cluster treatment in Arun tanks, was and produced only• toDeactivation provide sufficient of 1 superheat GE-Frame to prevent 5water Gas water transferrouted condensation pumps. to a condensate Decommissioningin the inter-cluster / water separator. pipelines.of these equipmentequipped saved with OPEX condensate-water and cut manpower separation, requirements by ~600 man-hours/year. The costsTurbine of Driven ACCP phasesBooster 1Compressor and 2 were – $1.25M6 and $0.75M respectively, with a total of 6 dayscondensate downtime transfer, and produced water required.MMSCFD The primaryfuel saving benefit from ACCPWith phasecompletionAfter 1 wasACCP of 6the phase MMSCFD LHP, 2 commissioning,Cluster of fuel 1 and savings. 2 the send LP Phase and a mixture 2 treatment provided of condensate facilities. an Theand LHPwater decommissioned to the Cluster 3 condensate- additional• Deactivation 3 MMSCFD of fuel 1 GE-Framesavings, and 3alsowater Gas was separator. criticalHP propane to Themaintaining productiondehydration pipeline separator systems integrity. inis Clusters nowOn an the overall onlyall activebasis, of those theseparation facilities invessel Cluster in Cluster 1 and 21 and 2. New liquid ACCP reduced the amount of Arun field pumpsactive equipment with smaller by almostduty and 60%, capacity base annual were installedO&M by $350K,in those and two fuel clusters to replace the old condensate pumps. consumptionTurbine by Driven 9 MMSCFD Power (Irani, Generator 2004). – 3 1, 2 and 3 were decommissioned, and gas thereby consolidated condensate-water Figure 4 shows process schematics of Clusters 1 and 2 before and after LHP. processing in those clusters relied on ambient MMSCFD fuel saving separation and treatment in Cluster 3 and • Reduction of annual base OPEX - $350K, including recertification, inspection, manpower and spare parts • Intangible cost reduction – logistics, propane consumption. The ACCP was executed in two phases. Phase 1 (2008) covered installation of 18” and 20” inter-cluster pipelines which served as the Cluster 2 booster compressor by-pass, while Phase 2 (2010) reconfigured the gas processing systems in Clusters 1, 2 and 3 to allow deactivation of the propane dehydration systems. Simplified process diagrams of ACCP Phases 1 and 2 are shown in Figure 3.

ACCP phase 2 addressed the concerns of gas dehydration performance in Clusters 1, 2 and 3 in the absence of the propane dehydration systems, which may lead Figure 4 - Arun LHP Schematic Drawing

Figure 4 - Arun LHP Schematic Drawing

19 SPE Java . Jan - Feb ‘14 4. The main benefit of this project was sulfur recovery, and tail gas treating. The and P-4 also experienced water breakthrough deactivation of oversized condensate pumps, acid gas removal process uses Sulfinol-M, in May 2010, and P-7 followed in June 2010. which eliminated a process integrity threat. a Shell proprietary solvent. The acid gas is NSO platform liquid handling facilities are Below turndown limit, the condensate pumps then processed in the sulfur recovery unit designed to separate condensate and water. vibrated excessively, resulting in small leaks at with a series of 3 claus reactors. The tail gas The produced water stream is discharged weld joints. Each condensate pump consumes unit consists of a hydrolysis/ hydrogenation overboard, subject to regulatory oil in water 690 HP electric power, the largest power reactor, followed by a Flexsorb absorption unit (OIW) limit of 50 ppm. consumers in Cluster 1, 2, and 3 after ACCP (ExxonMobil proprietary). The NSO treated phase 2 was commissioned. Deactivation gas contains 22% CO2 and 200 ppm H2S, The objective of the NSO Liquid Handling of two condensate pumps enabled 15- similar to the composition of the Arun field gas. Debottlenecking Project was to increase 20% reduction of Arun Clusters power The NSO gas is compressed, then combined capacity to 3,000 BPD, thus delaying the consumption. In addition to the condensate with gas from Arun and SLS fields as feed to onset of off-plateau production decline from pumps, the LHP also eliminated several other the PT Arun NGL plant. 4Q 2010 to 2Q 2011. The corresponding types of equipment, including condensate- production benefit was acceleration 6 of 2,782 water separators, produced water treatment NSO Liquid Handling Project MMSCF in the time period from July 2010 to tanks, and produced water transfer pumps. The NSO reservoir is strongly water-driven. September 2012. The project began with a Decommissioning of these equipment saved Consequently, water breakthrough occurred study chartered in 2009 to assess potential OPEX and cut manpower requirements by when the gas-water interface reached the facilities de-bottlenecking opportunities for ~600 man-hours/year. perforation zone, leading to a substantial achieving 3,000 BPD liquid handling capacity. increase in water production rate. The platform The de-bottlenecking study identified a phased With completion of the LHP, Cluster 1 and 2 was originally designed for 2,500 BPD liquid approach to increase liquid handling capacity, send a mixture of condensate and water to the handling capacity. As water production beginning with a bypass line to reduce flow Cluster 3 condensate-water separator. The continued to increase, the liquid handling restriction, through physical modification production separator is now the only active system eventually became a gas production of equipment to increase capacity. Major separation vessel in Cluster 1 and 2. New bottleneck. equipment additions were not considered liquid pumps with smaller duty and capacity feasible due to footprint limitations on the were installed in those two clusters to replace In preparation for water breakthrough, a platform. Another concern with excessive the old condensate pumps. Figure 4 shows reservoir simulation was completed in 2009 modifications was the necessity for hot-work process schematics of Clusters 1 and 2 before which indicated that NSO liquid production (welding, grinding, etc.), which would have and after LHP. would exceed 3,000 BPD in 2011. Without de- resulted in lost production, jeopardizing the bottlenecking of liquid handling facilities, gas project economics. North Sumatera Offshore (NSO) production was predicted to go “off-plateau” in Development 4Q 2010. This was roughly six months earlier The project was executed in three phases. The NSO field was discovered in 1972. than previous predictions based on reservoir Phase 1 removed turbine meter located Development was initiated in 1997. The field capacity and wellbore hydraulics. downstream of SWFD to reduce flow is located approximately 100 km from the restriction. This phase is executed in 4th North Aceh coast in the Malaka Strait. The Increased liquid production on NSO platform quarter of 2010 and increased liquid handling NSO reservoir gas is lean, with 33% CO2 and was first observed in 2009. Water samples capacity from 2,500 BPD to 2,800 BPD. The 1.5% H2S. NSO started production in 1999 from well testing in late 2009 showed high turbine meter function itself was substituted with nine wells. The reservoir mechanism is chloride content from well P-5 (6,500 - 8,700 by another meter. Phase 2 consisted of three pressure depletion, aquifer support and rock mg/L), indicating production of formation main scopes, namely: upsizing hydrocyclone compressibility. All wells are deviated except water. Following P-5 water breakthrough, P-8 control valves (LV-4843 and FFV-4843), re- 7 P-5. The initial reservoir pressure was 1946 psia. A 2008 pressure survey showed reservoir pressure of 1591 psia.

NSO surface facilities consist of two main parts: An offshore platform and onshore sour gas treating unit. The platform was designed to handle 450 MMSCFD of gas (later increased to 475 MMSCFD), equipped with gas / liquid separation, glycol dehydration, condensate-water separation, and overboard water treatment. Dry gas and separated condensate are jointly exported through a 100 km, 30” multiphase pipeline to the onshore facilities, which are operated by PT Arun NGL. These consist of three main processing units: acid gas removal, Figure 5 - NSO Liquid Production Profile Figure 5 - NSO Liquid Production Profile

Several additional items were initially considered, but were found to be unnecessary on the basis of performance testing, thus providing an opportunity to reduce project cost from $600K to $50K: 20 1. Hydrocyclone upsize (not required as hydrocyclone is bypassed and new chemical used) – cost reduction $210K SPE Java . Jan - Feb ‘14 2. Online OIW analyzer upgrade (not required as existing analyzer was found to be repairable) – cost reduction $50K 3. Variable frequency driver (VFD) on CDD pump to avoid high liquid level (not required after recycle line from CDD is routed to EWSD) – cost reduction $44K 4. New chemical injection skid (not required following improvements to existing chemical skid) – cost reduction $100K

The project scope as described above is shown in Figure 6.A key element of the NSO Liquid Handling Project was replacement of the oil – water separation chemical. Through field tests conducted with the chemical supplier in 2010, a new chemical was observed to deliver superior separation performance, maintaining low OIW content even while bypassing the hydrocyclones. Following full implementation of all phases of the NSO Liquid Handling Project, platform liquid handling capacity was increased to 3,500 BPD, 500 BPD higher than the original project objective. The project was deemed very successful, completed well within budget and available footprint limitations with results exceeding expectations.

Figure 5 - NSO Liquid Production Profile

Several additional items were initially considered, but were found to be unnecessary on the basis of performance testing, thus providing an opportunity to reduce project cost from $600K to $50K: 1. Hydrocyclone upsize (not required as hydrocyclone is bypassed and new chemical used) – cost reduction $210K 2. Online OIW analyzer upgrade (not required as existing analyzer was found to be repairable) – cost reduction $50K 3. Variable frequency driver (VFD) on CDD pump to avoid high liquid level (not required after recycle line from CDD is routed to EWSD) – cost reduction $44K 4. New chemical injection skid (not required following improvements to existing chemical skid) – cost reduction $100K

is critical in ensuring the long- term success of the field; Geomechanical modeling of the reservoir should be done early in field life to understand the long-term impact of reservoir depletion on wellbore stability and formation subsidence. 3. Drilling into depleted low-pressure reservoirs requires state-of-the-art under balanced drilling technology to minimize reservoir damage. 4. Innovative methods for utilizing all existing infrastructure in the field need to be evaluated continuously: Upgrading existing compressors and dehydration facilities can reduce wellhead pressures and keep low rate wells flowing longer; ACCP Figure 6 - NSO Liquid Handling Project Process Flow Diagram and LHP achieved mature field management objective at Arun to sustain routing recycle line from CDD to EWSD instead following improvements to existing profitability through equipment count of SWFD to reduce flow restriction, and water- chemical skid) – cost reduction $100K reduction, operation and maintenance oil separation chemical replacement. The new cost saving, fuel saving, and manpower chemical enabled water-oil separation process The project scope as described above is requirement reduction. without hydrocyclone while still meeting OIW shown in Figure 6.A key element of the NSO 5. Performance testing is essential for NSO specification on overboard water. This phase Liquid Handling Project was replacement of the Liquid Handling Project to define most was executed in 2nd quarter of 2011 and oil – water separation chemical. Through field cost effective scopes while delivering increased liquid handling capacity from 2,800 tests conducted with the chemical supplier in higher performance than original project BPD to 3,000 BPD. Phase three installed 2010, a new chemical was observed to deliver objective. automatic snap-acting valve on the by-pass superior separation performance, maintaining line of the hydrocyclone downstream of the low OIW content even while bypassing the This article summarizes the following SPE SWFD. Separation performance reduction hydrocyclones. Following full implementation Papers : due to hydrocyclone bypass is compensated of all phases of the NSO Liquid Handling 1. Pathak, P., Fidra, Y., Avida, H., Kahar, Z., Agnew, by superior chemical performance. Liquid Project, platform liquid handling capacity was M., Hidayat., D., ”The Arun Gas Field in Indonesia: Resource Management of a Mature Field”, SPE handling capacity was increased to 3,500 increased to 3,500 BPD, 500 BPD higher than Paper No. 87042, Indonesia, 2004. Presented at the BPD. The liquid handling capacity profile for the original project objective. The project was SPE Asia Pacific Conference, Kuala Lumpur, 29-30 each phase is shown in Figure 5. deemed very successful, completed well within March 2004. budget and available footprint limitations with 2. Avida,H., Soedarmo, A.A.,Utama, D.P., ”Aceh Operations Mature Field Management: Arun Asset Several additional items were initially results exceeding expectations. Consolidation and North Sumatra Offshore (NSO) considered, but were found to be unnecessary Liquid Handling”, SPE Paper No. 165929,Indonesia, on the basis of performance testing, thus Conclusions 2013. Presented at the SPE Asia Oil & Gas providing an opportunity to reduce project cost 1. The Arun gas field development has been Conference, Jakarta, 22-24 October 2013. from $600K to $50K: one of the most technically challenging References corresponding to the above and also one of the most successful gas mentioned papers: 1. Hydrocyclone upsize (not required as development in the world. The technologies 3. Irani, T., Susanto, T. H., Syarifah, T., Widjaya, P. T., hydrocyclone is bypassed and new developed for the field have proven to be Daud, M., Susanto, E., “Mature Field Management- Production Facilities Asset Consolidation and chemical used) – cost reduction $210K extremely important in ensuring excellent Reservoir Management”, IPTC Paper No. 12674, 2. Online OIW analyzer upgrade (not required ultimate recoveries from a deep, high Kuala Lumpur, 2008. as existing analyzer was found to be temperature, high pressure reservoir. The 4. Alaydrus, M. U., Bordeloen, T. P., ”Boosting repairable) – cost reduction $50K success of Arun is based on the insight, Deliverability in the Giant Arun Gas Field”, SPE Paper No. 22997, Presented at SPE Asia Pacific 3. Variable frequency driver (VFD) on CDD hard-work and efforts of engineers, Meeting, Perth, 4-7 Nov. 1991. pump to avoid high liquid level (not required operations personnel, geoscientist, and 5. Soeparjadi, R., “Geology of the Arun Gas Field”, J. after recycle line from CDD is routed to business professionals over the past ~40 Pet. Tech, pp. 1163 – 1172, June.1983. EWSD) – cost reduction $44K years 6. Dewi, R.A., “NSO Liquid Handling Study Charter”, 4. New chemical injection skid (not required 2. The initial design of the field development Mobil Exploration Indonesia Inc., February 2010.

21 SPE Java . Jan - Feb ‘14 SPE Workshop: Floating Lique ed Natural Gas (FLNG) .BZt1FSUI "VTUSBMJB SPE Workshop: Floating Lique ed Natural Gas (FLNG) Floating.BZt1FSUI "VTUSBMJB LNG (FLNG) has received considerable attention in recent years. Final investment decisions have been taken on several projects including Shell Prelude in Australia, Petronas Kanowit in Malaysia and Paci c Rubiales/Exmar in Colombia. These have given con dence to decisionFloating makers LNG to (FLNG) select has FLNG received concepts considerable for gas attention eld developments, in recent years. and Final there investment are many decisions in pre-FEED have and been FEED taken phases. on several The projects selection of FLNGincluding is being Shell made Prelude not only in Australia, for previously Petronas stranded Kanowit ingas Malaysia elds, and but Paci c also forRubiales/Exmar elds that would in Colombia. traditionally These have have given been con dence developed to with onshoredecision liquefaction makers to facilities. select FLNG concepts for gas eld developments, and there are many in pre-FEED and FEED phases. The selection of FLNG is being made not only for previously stranded gas elds, but also for elds that would traditionally have been developed with The termonshore FLNG, liquefaction or LNG FPSO, facilities. depicts a range of concepts from small quay-side barge mounted liquefaction units to 8 million tonnes per year full eld oating production, liquefaction, storage and ooading facilities in remote harsh environments. They have in common the integrationThe term of FLNG, facilities or LNG and FPSO, technologies depicts a range from of concepts onshore from LNG small and quay-side oshore barge marine mounted oating liquefaction production units facilities. to 8 million Issues tonnes of per safety, reliability/availability,year full eld oating operations, production, maintainability, liquefaction, storage as well and as ooading the quali cation facilities in of remote new technologies,harsh environments. need They to be have dealt in common with by separatethe specialistsintegration that are of not facilities normally and closely technologies interacting. from onshore LNG and oshore marine oating production facilities. Issues of safety, reliability/availability, operations, maintainability, as well as the quali cation of new technologies, need to be dealt with by separate specialists that are not normally closely interacting. The workshop will provide an overview of the key drivers for LNG developments and will focus on selection of the appropriate technology and the inherent technical and commercial challenges for FLNG facilities. The workshop will provide an overview of the key drivers for LNG developments and will focus on selection of the appropriate technology and the inherent technical and commercial challenges for FLNG facilities. Key Highlights: t1SPDFTTBOE'BDJMJUJFT&OHJOFFSJOHKey Highlights: t1SPKFDU&YFDVUJPO t.BSJOF'BDJMJUJFTBOE&OHJOFFSJOHt1SPDFTTBOE'BDJMJUJFT&OHJOFFSJOH t/FX5FDIOPMPHJFT$VSSFOU'-/(BOE'140 t1SPKFDU&YFDVUJPO t1SPDFTT4BGFUZ 3JTLBOE.JUJHBUJPOTt.BSJOF'BDJMJUJFTBOE&OHJOFFSJOH t1BOFM4FTTJPOPOUIFi'VUVSFPG'-/(w t/FX5FDIOPMPHJFT$VSSFOU'-/(BOE'140 t0QFSBUJPOTBOE.BJOUFOBODFt1SPDFTT4BGFUZ 3JTLBOE.JUJHBUJPOT t1PTUFS4FTTJPO t1BOFM4FTTJPOPOUIFi'VUVSFPG'-/(w t0QFSBUJPOTBOE.BJOUFOBODF t1PTUFS4FTTJPO

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22 SPE Java . Jan - Feb ‘14 TANGGUH THE CONTROVERSY R.S. Trijana Kartoatmodjo

angguh gas sales to China will Shortly after the conclusion of Tangguh and then we still had to wait outside. There always attract controversy. One negotiation, I was requested to clarify the were no more red carpets. For Tangguh, we Tneeds to understand the background sales decision before oil and gas seniors in a were competing against thirteen other LNG at the time of the negotiation to appreciate marketing forum. I explained to all dignitaries, sellers, all with similar gas price formulations the decision taken. In late 1990s and that the market had changed from seller- and values. early 2000s, the domestic market for gas driven to buyer-dominant. was nonexistence. At the same time, with Tangguh sales are already concluded. It is declining oil production, the economy of the In the 1970’s, after the Arab crisis, gas sellers done, part of history we cannot change. So country depended more than ever on income to Japan were greeted with a red carpet. Indonesia must wait for the next price re- from natural gas resources. Developing But during Tangguh gas sales negotiations, negotiation in the contract, which happens infrastructure for domestic gas was not a sellers had to knock hard on buyers’ doors, every four years after the first LNG shipment. viable option.

be carried in Road Tankers, Rail Tankers or burning fossil fuel and it has emerged in special ISO container units. The world’s as the environmentally preferred fuel of LNG first LNG tanker, the Methane Pioneer, choice. safely carries LNG from Lake Charles, LA., • Liquefied natural gas is a clear, non- to Canvey Island, United Kingdom, initiating corrosive, non-toxic, odorless liquid. commercial LNG shipping in 1959. • LNG’s weight is less than one-half that of water for an equivalent volume. In 1984 Japan became the biggest LNG importer, purchased 72% of world’s LNG, LNG achieves a higher reduction in volume FACTS using 75% for electricity generation. South than compressed natural gas (CNG) so that Korea received its first LNG shipment from the /volumetric/ energy density of LNG is 2.4 atural gas was first liquefied (cooling Indonesia in 1986, while Taiwan’s first LNG times greater than that of CNG or 60 percent natural gas to form Liquid Natural terminal receives a shipment from Indonesia of that of diesel fuel. This makes LNG cost NGas) in the 19th century by Michael in 1990. efficient to transport over long distances Faraday and Karl Von Linde. A patent for LNG where pipelines do not exist. was filed in 1914. The liquefied natural gas industry has a long and excellent record, due to strict industrial Liquefied natural gas, or LNG, is natural gas safety standards applied worldwide. Until that has been supercooled to minus 260o now there have been over 56,000 Liquefied Fahrenheit (minus 162o Celsius). At that natural gas carrier voyages, covering more temperature, natural gas condenses into than 140 million miles, without a significant a liquid. When in liquid form, natural gas accident or problem, either in port or on the takes up to 600 times less space than in its high seas. gaseous state. First commercial natural gas liquefaction plant built in West Virginia in Liquefied natural gas has an excellent 1917. record in all aspects of liquefaction, shipping, storage and regasification. This is due to both Liquefied natural gas (LNG) is natural gas the high technical standards that are used in (predominantly methane, CH4 at least 90%) construction and operation, and the physical that has been converted to liquid form for ease properties of liquefied natural gas: of storage or transport over long distances. Large quantities of LNG can be carried by • Natural gas is only flammable when specially designed cryogenic sea vessels mixed with air in concentrations (LNG carriers) or cryogenic road tankers are between 5 and 15%. used for its transport. Smaller quantities can • Natural gas is the world’s cleanest

23 SPE Java . Jan - Feb ‘14 LNG FOR POWER GENERATION IS A LUXURY THAT INDONESIA CAN’T AFFORD H. L. Ong, Department of Geology, Institut Teknologi Bandung

he Dewan Energy Nasional (DEN) its mineral resources. Australia after some The Bontang LNG can be sold easily to Taiwan or National Energy Commission hesitation finally signed the Kyoto Protocol, based on existing contract at $17/mmbtu. Tproposal regarding the various but it also has cost problems for electricity There is a $6/mmbtu difference between the Indonesia’s future mix of energy sources generation, particularly in states that closed gas sold to Taiwan and that sold domestically to was approval by the DPR (parliament) on their coal generating power plants. PLN Muara Karang. The discount for PLN is a January 28, 2014. According to DEN, the thinly veiled subsidy by the Government. If the country’s overall energy requirements in 2025 LNG for power generation is a very expensive true market for LNG is used in the calculations, will be 30% coal, 22% gas, 25% oil, and 23% exercise, as shown in the following rough the final cost to PLN Muara Karang, which is alternatives. The alternative sector will thus calculation for the LNG Bontang sold to PLN part of the Government monopoly on electrical jump four fold from its present 6%, mainly due Muara Karang. Because it is for domestic power, would be $21/mmbtu. to an increase in geothermal energy. purpose, the LNG, was sold at a cheaper price of $11/mmbtu than the usual export price. The In May 2012, before the RSUP received its The energy source mix proposed by DEN is LNG must be transported to Jakarta, say at first shipment from Bontang, the Government clearly appropriate to rich nations. Indonesia $1/mmbtu. Upon arrival the LNG must be increased the price of pipe gas from $2-3/ should instead be oriented towards the converted back to gas before it can be used mmbtu to $5-6/mmbtu. This long delayed developing countries such as China and by PLN. The regassing is carried out by a policy by doubling in price after more than 10 India. For example, China’s energy policy private company, PT. Nusantara Regas. Given years, is probably to anticipate the high cost of aims for 70% coal, 4% gas, 1% oil, and 25% the monopoly to a private company, we can importing LNG from Bontang. alternatives for its power generation in 2030. assume that the cost of regassing, will be around $3/mmbtu. In other words, the total To be fair to K3S, the Government should LNG will be used in a big way for power cost to transport the gas from Bontang to PLN increase the price of K3S for delivery PLN generation in Indonesia. The Jakarta bay Muara Karang is around $15/mmbtu. Muara Karang from $5-6/mmbtu to $21/ Floating Storage Regassification Unit (FSRU) operated by PT Nusantara Regas, received its first LNG shipment from Bontang in September 2012 to supply PLN Muara Karang. Three other receiving terminals will be built in Semarang, Lampung, and Arun.

Indeed, Indonesia will be proud to use its abundant LNG for power generation. It’s clean. But at what cost?

It is true that Indonesia has signed the Kyoto and Copenhagen protocols and therefore bound to have a clean energy policy. However, Indonesia as well as China and India are all still allowed to use “dirty coal”. Further, it is noteworthy that the US, even with intense pressure from European countries, has refused to sign the Kyoto Protocol, because doing so inevitably will increase energy costs. Canada did sign the Kyoto Protocol, but now it is hesitating due to the high cost of developing

24 SPE Java . Jan - Feb ‘14 Indonesia has been exploring geothermal for over 35 years and new exploration blocks have been issued. The result so far is not too promising. There is not enough incentive or the incentive came too late which is most often the case. In addition, geothermal is like oil, it needs at least 10 years before any significant production can be expected. The best answer for the near future is coal. Indonesia has at least 200 years reserve based on the present consumption. This reserve will be doubled if lignitic coal is used in power generation, which is currently rejected as overburden. Many countries like Thailand, and even in the Australian state of Victoria, lignitic coal of 2000 kcal is now being used. It’s the cheapest of all forms of energy at present with proven technology (Note: There are plenty cheaper forms of energy such as solar, wind, waves, tides, hot rocks, waste, etc. but the Still many prospective places to drill technology is not there yet and therefore all of them still have to be subsidized heavily). mmbtu. This will undoubtedly increase gas price that PLN is willing to pay before May exploration activities both in Java and in 2012 is only $2-3/mmbtu. Even after May, it is The sacrifice in using coal is having dirty air. South Sumatra, for stranded gas as well as only $5-6/mmbtu. Instead of offering higher Very heavy pollution is shown in this picture CBM which requires a higher price for its prices to K3S, the Government decided to taken during the Beijing Olympics (Fig.3). development. For this price, or even half of “import” LNG from Bontang at $21/mmbtu. However, Indonesia’s cheapest type of coal it at $10.50/mmbtu, K3S would be willing to is ranked low mainly due to its water content, build pipeline infrastructure, estimated at $1-3/ In summary, LNG is just a vehicle for ease of not the ash or sulphur which causes the smog. mmbtu, which eventually will benefit all the transportation. It is very expensive because it In addition Java is an island and the tropical stranded gas owners. needs to be liquefied at $4/mmbtu and then rain will clear the sky, in contrast to China, a regas at $3/mmbtu before it can be used. continent, where the smog stays circulating. There are still oil and gas to be found in Java Because of the high cost, it should be used for and South Sumatra. Fig. 1, taken from Newton International export only, where the market is It should be noted that Indonesia is proud (2004), shows that Indonesia still has a steep still lucrative and the Government of Indonesia to be the largest exporter of thermal coal in creaming curve, especially for gas. Fig. 2, taken is making a handsome profit for the last 35 the world. China produces four times that of from Woods Mackenzie (2013) shows that the years. This profit can be maintained if PLN is Indonesia and India produces 50% more coal. creaming curve for both Java and Sumatra are willing to increase the price of gas in Java and However, both countries are not exporting still significant and therefore production can South Sumatera, which is now $5-6/mmbtu, any coal but instead they are importing coal be increased significantly, if more drilling is to the same price level as importing LNG from from Indonesia in large quantities. Indonesia carried out. The amount of drilling depends on Bontang at $21/mmbtu or even half of it at for its power generation should follow the the price of gas that the Government is willing $10.50/mmbtu. The increase in price can then developing country policy using lignitic coal to pay to its contractors. At present, instead be used to explore for more gas and to build of 2000-4000 kcal and export the higher rank, of exploration, the Government is taking the the pipeline infrastructure. instead of using the expensive but clean LNG easy road to take the expensive but readily that Indonesia cannot afford. available LNG to supply Java. The question then becomes: Do we have an alternative to It is worthy to note that in 2004, Chris Newton, LNG for power generation then chairman of the Indonesian Petroleum in Java and South Sumatra Association, in his opening speech at the where it is most needed? annual convention had mentioned the fact that The answer is definitely yes. “Diesel is currently imported at over $7/mmbtu, But we have to make some however, gas is priced at less than $3/mmbtu sacrifices. domestically”. The Government has always been slow, hesitant, and very reluctant to give DEN proposed to accelerate profit or incentives to its contractors who have the use of geothermal energy been operating in Indonesia for decades. If and suggested for a fourfold there was an incentive, it comes way too late. increase by 2025 which is The policy of delaying has its effect today. The only 11 years from now. present shortage of gas in Java is due to the This will be very difficult if reluctance of the oil companies to explore. The not impossible to achieve. Beijing Stadium Before the Olympics in 2008

25 SPE Java . Jan - Feb ‘14 LNG Stories and Indonesia’s (Shrinking) LNG Industry

Bambang Istadi, Energi Mega Persada & SPE Java Chairman he tragic earthquake that hit Japan a policy prompted by the first oil shock from only. This was 3.3 mtpa lower than 2011. in March 2011 could be considered a the Arab embargo of 1973. Japan reduced In contrast, in 2012 our neighbors Malaysia T“game changer” for the LNG industry. its dependence on oil, and moved towards produced 23.1 mtpa, Australia 20.8 mtpa and At that time, LNG was experiencing a sluggish a more diversified energy portfolio. Natural Brunei 6.8 mtpa. The Arun plant relies on gas demand. Following the Fukushima power gas now supplies 15% of Japan’s energy supply from the heavily depleted Arun and plant accident, Japan shutdown of 52 out of requirements, up from 3% in 1975. This shift NSO fields. Reports suggest the plant may 54 nuclear powered power plants, and so turned the country into a pioneer of global LNG stop operating by 2014 when current LNG natural gas-fired generation was substituted trade. Japan was the driving force behind the contracts expire. LNG production from Badak for the lost nuclear capacity. Japan’s LNG development of the Indonesian LNG industry: is also in decline; from 18 mt in 2007 to 14.4 demand jumped by almost 12% to about 79 both the Arun and Badak LNG developments mt in 2011. Only Tangguh with 23 Tcf proved mt, which created a tight market, and pushed in the mid-70s were underpinned by supply probable and possible reserves had sufficient LNG prices up to $16-17/mmBtu towards contracts to Japan. Indonesia quickly grew gas supply for plant expansion and to support the end of 2011. Australia benefited most into the largest LNG exporter in the world. new sales commitments. from the “windfall” and became the largest supplier of LNG for Japan in 2012. On the Indonesia’s LNG is produced at three Indonesia’s role as a prominent LNG producer other hand, Indonesia, also a major supplier locations. The Arun plant, near Lhokseumawe and exporter is diminishing. In 2006, Qatar of LNG to Japan, did not have surplus LNG to in Aceh, has 6 trains having a total capacity surpassed Indonesia to become the largest tap into this opportunity. In fact, since 2002, of 12.5 mtpa. The Badak plant in Bontang, exporter of LNG in the world. Currently, Indonesia has struggled to deliver contracted East Kalimantan, has 8 trains having a total Qatargas is the largest LNG producer in LNG volumes due to depleting gas fields and capacity of 22.5 mtpa. The Tangguh plant, the world, with an annual LNG production rising domestic demand, to the point where the third and newest LNG hub in Indonesia capacity of 42 mtpa. Together with RasGas, Indonesia has been forced to buy LNG spot which came online in 2009, has two trains Qatar reached a record LNG production of 77 cargoes to meet export obligations. having a total capacity of 7.6 mtpa. Despite mtpa in December 2010. this huge 42.6 mtpa of installed capacity, Japan is the world’s largest importer of LNG, in 2012, Indonesia produced 18.1 mtpa Despite recent shortfalls, hope remains.

26 SPE Java . Jan - Feb ‘14 terminal in Melaka from Nigeria LNG Ltd.’s Bonny Island terminal. Malaysia is planning several other receiving and regasification terminals such as the Lumut (Lahad Datu) LNG FSU Terminal and Pengerang LNG Terminal. Things change fast. These countries were NOT considered to be potential LNG importers a decade ago. Indonesia could well be importing LNG sooner than anticipated. Indonesia signed its first LNG import deal at the end of 2013 for 0.8 mt of LNG supply a year from U.S.-based Cheniere Energy Inc for 20 years beginning in 2018. Over the past decade, Indonesia’s domestic gas demand rose steadily by around 2.5% annually to In 2011, Indonesia was still the 8th largest operations. around 4.3 bscf/d in 2011. exporter of natural gas. In January 2012, the Oil & Gas Journal stated that Indonesia With the exception of Abadi LNG, the other From the LNG market perspective, construction had 141 Tcf of proven natural gas reserves, projects are relatively small scale owing to the of new receiving terminals should boost LNG making it the 14th largest holder of proven small reserves within the respective areas. demand, as the two largest importers, Japan natural gas reserves in the world, and the and Korea, are saturated with limited future third largest in the Asia-Pacific region. The majority of Indonesia’s undeveloped growth. China and India are two countries However, the vast majority of these reserves gas resources lie in the East Natuna with tremendous LNG growth potential, but are in remote areas and will be challenging D-Alpha Block. Discovered in 1970 by Italy’s currently LNG is less than 40% of total gas to develop. Agip, the field is the biggest in Indonesia consumption. So LNG demand in Asia should and Southeast Asia with an estimated 46 continue to be resilient in the future driven by Several LNG projects are being planned or Tcf of recoverable gas. Despite Exxon’s the economic growth that stimulates demand. constructed which could improve Indonesia’s $400m and Pertamina’s $60m investments, Outside of Asia, the story is quite different. In LNG output. The next anticipated LNG facility the Indonesian Government terminated the US, exponentially increasing shale gas in Indonesia would be the Donggi-Senoro 2 its contract with Exxon in 2009 leaving production has reduced LNG imports; and mtpa liquefaction plant in Central Sulawesi. Pertamina in charge. The fate of the Block also for its neighbors Canada and Mexico The project developers (Mitsubishi, Kogas, and the estimated $52 billion development due to the interconnectedness of the North Pertamina, and Medco) signed a final is pending and still being negotiated with the American gas grid. Europe’s share of global investment decision in early 2011, and expect Government and discussed among potential LNG demand fell 20% in 2012 – a level not the US$ 2.8 billion, 370 Bcf/y plant to come partners (Pertamina, ExxonMobil, Total and seen since 1980. In 2012 specifically, the online in 2014/2015. Gas will be supplied PTTEP). increased competitiveness of coal, availability from the nearby Matindok and Senoro-Toili of renewable power and higher pipeline gas gas fields which have Proved reserves of 1.6 The current East Natuna development scheme imports depressed LNG demand. Tcf and Probable reserves of 0.6 Tcf. Inpex includes gas export by pipeline to neighboring discovered the giant Abadi gas field in 2000 in countries. LNG could be a viable alternative. East Natuna however, has been little explored deep waters between Timor and Australia. It Many LNG receiving and regasification over the last 15 years, mainly due to political will be developed as floating LNG in phases. terminals are being built or planned in the disruption, its remoteness, and could prove The first phase will be a 2.5 mtpa floating region, including Indonesia, which currently uneconomic to develop. Reservoirs in the LNG, underpinned by 9 tcf of 1P reserves. has a floating LNG receiving and regasification region are in the Middle to Late Miocene reefs, Inpex received government approval in 2009 terminal off Jakarta. This Nusantara to develop the project in the Arafura Sea, FSRU is a joint venture between but non-technical issues have delayed first Pertamina and PGN. The FSRU gas to 2020+. Another planned project is the has total contracted LNG supplies Sengkang LNG in South Sulawesi, a mini 0.5 of 11.75 mt over 2012-2022. Other mtpa modular LNG plant being developed terminals are under construction by Energy World Corporation. Following the and will come on stream in the approval of PoD in mid-2011, EWC have coming years. These include partial mobilized major equipment including cold conversion of the Arun LNG export boxes and ancillary equipment which have facilities into a receiving terminal, arrived on site in August 2012. The source of and the Lampung, Cilacap and the gas is from the 120 Bcf of Proved reserves East-Central Java LNG FSRU’s. and 45 Bcf of Probable reserves from Energy Regionally, in 2013, Singapore Equity’s operated Wasambo gas fields. The began receiving LNG cargoes and estimated $350 million project is waiting for Malaysia received its first LNG approvals and necessary license for LNG cargo at its Sungai Udang receiving

From the LNG market perspective, construction of new receiving terminals should boost LNG demand, as the two largest importers, Japan and Korea, 27are saturated with limited future growth. China and India SPE Java . Jan - Feb ‘14 are two countries with tremendous LNG growth potential, but currently LNG is less than 40% of total gas consumption. So LNG demand in Asia should continue to be resilient in the future driven by the economic growth that stimulates demand. Outside of Asia, the story is quite different. In the US, exponentially increasing shale gas production has reduced LNG imports; and also for its neighbors Canada and Mexico due to the interconnectedness of the North American gas grid. Europe’s share of global LNG demand fell 20% in 2012 – a level not seen since 1980. In 2012 specifically, the increased competitiveness of coal, availability of renewable power and higher pipeline gas imports depressed LNG demand.

East Natuna however, has been little explored over the last 15 years, mainly due to political disruption, its remoteness, and could prove uneconomic to develop. Reservoirs in the region are in the Middle to Late Miocene reefs, underlain and overlain by deltaic sediments. The 71% CO2 content made gas extraction from the huge resources is expensive, and development difficult. Even if it gets to be developed, it would have to compete with other projects targeting the same markets. In particular Australia burgeoning LNG industry, where the export capacity is set to expand substantially as new LNG facilities and expansions of existing facilities come online within the next decade. LNG plants reported under construction include the Australia Pacific, Gladstone, Gorgon, Ichthys, Prelude, Queensland Curtis, Wheatstone and few others being planned. Turning these projects into reality however, challenging and faces many hurdles such as rising costs and environmental issues. In the longer term however, as less expensive gas from Russia and the US become available and is brought online, future LNG project will potentially face competition on a more global scale. If such is the case, then the development of the largest gas deposit in Indonesia may not happen anytime soon.

Expensive development, supply competition and available markets are key issues faced by the industry. Other factors that may come into play particularly Indonesia is project financing. Most if not all of Indonesia’s LNG development in the past depended heavily on the relatively “cheap” Japanese financing based on long-term LNG sales purchase agreements. The LNG pricing is typically based on oil-linked JCC (Japanese Crude Cocktail). The industry however, is seeing a shift from the long-term contracts to spot sales. In 2011, LNG spot market grew by almost 32%, or 15 mt, to reach 62 mt – just over a quarter of the LNG trade. By comparison, the spot market made up only 16% in 2006. If the trend continues and the market prefers a more flexible supply through purchase of spot market, how will Indonesia secure financing to develop its LNG industry in the future? Could LNG industry be developed based on domestic market? Oil majors prefer export to overseas markets that offer higher prices while the government is unwilling to extend gas contracts and divert gas supplies to meet high domestic gas demand growth. Payment securitization remains an issue for oil majors if gas is sold domestically even though the trend of increasing gas price looks promising, in particular if oil subsidies are lifted which will impact in improved gas pricing. But, the willingness of domestic market to pay for higher LNG price is yet to be tested.

Perhaps the above factors are not as important as finding more gas giants. Exploration opportunities still exist in the deeper stratigraphic layers of mature basins. Discoveries in Pre-Tertiary sections of the Baram Delta, Sarawak, could trigger interest in analogous geological settings in Indonesia. The disappointing results of deepwater exploration in the Eastern part of Indonesia however, could hinder oil companies from further exploration activities. Even if gas were discovered, it would take years to develop. The problems and challenging issues faced by the industry in recent years such as tax, the many permits, and abolishment of BPMIGAS and uncertainty of contract extension could hamper exploration activities and further delay the discoveries of the much needed gas resources. We are seeing a trend of decreasing exploration acreage holdings of oil majors and some foreign companies exiting Indonesia which could be a bad signal for potential investors.

On the other hand, the domestic demand is healthy. According to the International Monetary Fund (IMF), Indonesia sustained relatively strong economic performance throughout the global recession, with an average GDP growth rate of just under 6 percent per annum for the past five years. A combination of healthy growth, market reforms, and a stable government encouraged rapid investment, particularly in the commodity sector. Moody's and Fitch Ratings both upgraded Indonesia's Sovereign Risk Rating to "investment grade" status between late 2011 and early 2012. So, in the short term the economic outlook looks bright, which could translate to Indonesia having to import its LNG needs to fuel its growth. the many permits, and abolishment of BPMIGAS and uncertainty of contract extension could hamper exploration activities and further delay the discoveries of the much needed gas resources. We are seeing a trend of decreasing exploration acreage holdings of oil majors and some foreign companies exiting Indonesia which could be a bad signal for potential investors.

On the other hand, the domestic demand is healthy. According to the International Monetary Fund (IMF), Indonesia sustained relatively strong Countries with large LNG exporting capabilities and future competitionseconomic that performance supply Indonesia’s throughout the global underlaintraditional and overlainLNG buyers by deltaic (Japan, sediments. Korea shift and from Taiwan) the long-term are contracts described to spot below. sales. Theserecession, are with important an average markets; GDP growth rate Theafter 71% all, CO2 Japan content and made Korea gas extractionare the world’sIn 2011, dominant LNG spot LNG market importers grew by almostand accountedof just under for 6 percent52% of per the annum LNG for the past from the huge resources is expensive, and 32%, or 15 mt, to reach 62 mt – just over a five years. A combination of healthy growth, developmentmarket. difficult. Even if it gets to be quarter of the LNG trade. By comparison, the market reforms, and a stable government developed, it would have to compete with spot market made up only 16% in 2006. If encouraged rapid investment, particularly otherQatar projects targeting the same markets. the trend continues and the market prefers a in the commodity sector. Moody’s and Fitch InQatar particular holds Australia more than burgeoning 27% of LNG global more liquefaction flexible supply capacity. through purchase Qatar has of spot been Ratings exporting both upgraded LNG since Indonesia’s 1997 Sovereign industry,by delivering where the initially export capacity5.7 Bcf is (0.16 set to millionmarket, tons) how ofwill LNGIndonesia to Spain. secure Byfinancing 2005 QatarRisk Ratinghad exported to “investment a total grade” of status expand substantially as new LNG facilities to develop its LNG industry in the future? between late 2011 and early 2012. So, in the and987 expansions Bcf (27.9 of million existing tons) facilities of comeLNG, toCould the LNGtraditional industry LNGbe developed buyers, based and onto othershort countriesterm the economic such asoutlook India, looks bright, onlineSpain, within Italy, the Belgium next decade. and LNG later plants to the domestic US and market? UK. Qatar Oil majors has two prefer LNG export companies which could called translate Qatargas to Indonesia and having to reportedRasGas under and construction both are located include inthe theto Rasoverseas Laffan markets Industrial that offer Port higher on prices the coastimport ofits LNG Persian needs Gulf. to fuel Theits growth. 2 Australiacompanies Pacific, added Gladstone, 5 of Gorgon, the country's Ichthys, 14while trains the government in 2009 and is unwilling 2010. toThe extend latest, the 14th train (Qatargas IV Prelude,Train 7), Queensland came online Curtis, in WheatstoneJanuary 2011. gas contractsLNG is andexported divert gas using supplies the to improvedmeet Countries carrying with capacities large LNGof Q- exporting and few others being planned. Turning these high domestic gas demand growth. Payment capabilities and future competitions that projectsMax and into Q-Flex reality however,vessels challengingthat result insecuritization lower transpo remainsrtation an issue costs for oilper majors journey supply whilst Indonesia’s through traditional economies LNG buyers and faces many hurdles such as rising costs if gas is sold domestically even though the (Japan, Korea and Taiwan) are described and environmental issues. In the longer term trend of increasing gas price looks promising, below. These are important markets; after all, however, as less expensive gas from Russia in particular if oil subsidies are lifted which Japan and Korea are the world’s dominant and the US become available and is brought will impact in improved gas pricing. But, the LNG importers and accounted for 52% of the online, future LNG project will potentially face willingness of domestic market to pay for LNG market. competition on a more global scale. If such is higher LNG price is yet to be tested. the case, then the development of the largest Qatar gas deposit in Indonesia may not happen Perhaps the above factors are not as Qatar holds more than 27% of global anytime soon. important as finding more gas giants. liquefaction capacity. Qatar has been Exploration opportunities still exist in the exporting LNG since 1997 by delivering Expensive development, supply competition deeper stratigraphic layers of mature basins. initially 5.7 Bcf (0.16 million tons) of LNG to and available markets are key issues faced Discoveries in Pre-Tertiary sections of the Spain. By 2005 Qatar had exported a total by the industry. Other factors that may come Baram Delta, Sarawak, could trigger interest of 987 Bcf (27.9 million tons) of LNG, to the into play particularly Indonesia is project in analogous geological settings in Indonesia. traditional LNG buyers, and to other countries financing. Most if not all of Indonesia’s LNG The disappointing results of deepwater such as India, Spain, Italy, Belgium and development in the past depended heavily exploration in the Eastern part of Indonesia later to the US and UK. Qatar has two LNG on the relatively “cheap” Japanese financing however, could hinder oil companies from companies called Qatargas and RasGas and based on long-term LNG sales purchase further exploration activities. Even if gas were both are located in the Ras Laffan Industrial agreements. The LNG pricing is typically discovered, it would take years to develop. Port on the coast of Persian Gulf. The 2 based on oil-linked JCC (Japanese Crude The problems and challenging issues faced companies added 5 of the country’s 14 trains Cocktail). The industry however, is seeing a by the industry in recent years such as tax, in 2009 and 2010. The latest, the 14th train

28 SPE Java . Jan - Feb ‘14 of scale has reduced the cost of transportation by 30 - 35 percent, giving Qatar a powerful competitive advantage.

According to the Oil & Gas Journal, as of January 1, 2011, natural gas reserves in Qatar were 896 Tcf; representing 14% of world's natural-gas reserves; the world’s third-largest reserves, behind Russia and Iran. Qatar's natural gas is located in the massive offshore North Field in the Persian Gulf. It is the world's largest gas field, which is a geological extension of Iran's South Pars Gas-Condensate field, which holds an additional 450 Tcf of natural-gas reserves. These gas reserves are equivalent to 215 billion barrels. On top of this is 16 billion barrels of condensate reserves. As an illustration of its magnitude, South Pars has an average gross pay zone thickness is 450m !!. The North Field, was discovered in 1971 by the completion of Shell's North West Dome-1 well, while the South Pars Field was discovered in 1990 by the National Iranian Oil Company (NIOC).

Qatargas produces LNG from its 4 ventures (Qatargas I-IV). Qatargas I operates 3 LNG trains with a capacity to produce 9.6 mtpa for Japan and Spain markets. The shareholders are Qatar Petroleum, ExxonMobil, Total, Mitsui and Marubeni. Qatargas II, operates 2 trains with a total capacity of 15.6 mtpa. It is a joint venture of Qatar Petroleum and ExxonMobil and supplies 20% of UK’s LNG needs. Qatargas III, a joint venture between Qatar Petroleum, ConocoPhillips and Mitsui operates 1 train with a capacity of 7.8 mtpa; while Qatargas IV is a joint venture between Qatar Petroleum and Royal Dutch Shell. Its train utilizes the same Air Product’s proprietary APX process technology as QG 2 and QG 3, and started production in early 2011, with a production capacity of 7.8 mtpa.

RasGas was established in 2001 and is the second-biggest LNG producer in the world after Qatargas. In June 1999, the first spot cargo loaded, marked a major milestone for RasGas. The cargo was the first LNG produced by Train 1, and was exported to KOGAS (Korea). RasGas competed its seventh LNG trains in 2009 which brought its total capacity to 36,3 mtpa.

In 2005, Qatar's placed a moratorium on further production projects on the North Field, to allow time to study field development optimization and to examine ways of sustaining high levels of output over the longer term.

Its train utilizes end of 2015. The second is Rotan FLNG, the same will monetize gas production from the Rotan Air Product’s field northeast of Sabah in the South China p r o p r i e t a r y Sea. The terminal has a design capacity of APX process 72 Bcf/y and could serve some domestic technology as demand in Sabah via the proposed Lahad QG 2 and QG Datu regasfication plant. The project partners, 3, and started Petronas, MISC and Murphy Oil partnership production in target a final investment decision for 2014 and early 2011, with commissioning by 2017. Altogether, proposed a production liquefaction projects and expansions are likely capacity of 7.8 to add about 337 Bcf/y to Malaysia’s export mtpa. capacity in the next few years.

RasGas was Malaysian LNG is exported to Japan, South (Qatargas IV Train 7), came online in January established in 2001 and is the second-biggest Korea, Taiwan and China on a long-term 2011.Malaysia LNG is exported using the improved LNG producer in the world after Qatargas. basis. MLNG also sells LNG on the spot carryingAs of 2009, capacities Malaysia ofwas Q-Max the second and Q-Flexlargest exporterIn June of 1999,LNG after the Qatar. first spot Malaysia cargo has loaded, been exportingmarket to the Asia region and the Atlantic vesselsLNG since that 1983 result from in Bintulu, lower in transportation the Malaysian statemarked of Sarawak. a major Themilestone Bintulu for facility RasGas. is one The of the Basin.largest LNG is primarily transported by costsLNG complexesper journey inwhilst the world,through it economiesconsists of of8 LNGcargo trains, was of thewhich first 3 belong LNG produced to MLNG bySatu Train (the firstMalaysia joint International Shipping Corporation scaleventure has - Petronas,reduced the Shell cost BV of and transportation Mitsubishi), 31, to andMLNG was Dua exported and 2 to to MLNG KOGAS Tiga. (Korea). The 8 production(MISC), which owns and operates 27 LNG trains have a total liquefaction capacity of 1.2 Tcf/y following the debottlenecking completed at the end by 30 - 35 percent, giving Qatar a powerful RasGas competed its seventh LNG trains in tankers, the single largest LNG tanker fleet in of 2010 at the Dua plant. The Bintulu complex also hosts Shell's GTL project, which converts natural competitive advantage. 2009 which brought its total capacity to 36,3 the world by volume of LNG carried. MISC is mtpa. 62-percent owned by Petronas. According to the Oil & Gas Journal, as of January 1, 2011, natural gas reserves in In 2005, Qatar’s placed a moratorium on Malaysia was the world’s tenth largest holder Qatar were 896 Tcf; representing 14% of further production projects on the North of natural gas reserves in 2010. According to world’s natural-gas reserves; the world’s Field, to allow time to study field development the Oil and Gas Journal, Malaysia held 83 Tcf third-largest reserves, behind Russia and optimization and to examine ways of of proven natural gas reserves as of January Iran. Qatar’s natural gas is located in the sustaining high levels of output over the 2013, and it was the third largest natural gas massive offshore North Field in the Persian longer term. reserves holder in the Asia-Pacific region. Over Gulf. It is the world’s largest gas field, which half of the country’s natural gas reserves are is a geological extension of Iran’s South Malaysia in its eastern areas, predominantly offshore Pars Gas-Condensate field, which holds an As of 2009, Malaysia was the second largest Sarawak. Most of Malaysia’s gas reserves additional 450 Tcf of natural-gas reserves. exporter of LNG after Qatar. Malaysia are associated with oil basins, although These gas reserves are equivalent to 215 has been exporting LNG since 1983 from Sarawak and Sabah have an increasing billion barrels. On top of this is 16 billion Bintulu, in the Malaysian state of Sarawak. amount of non-associated gas reserves. The barrels of condensate reserves. As an The Bintulu facility is one of the largest LNG prolific Sarawak’s Central Luconia basin is illustration of its magnitude, South Pars has complexes in the world, it consists of 8 LNG the primary source of gas, which was first an average gross pay zone thickness is trains, of which 3 belong to MLNG Satu (the discovered in the 1960s. The reservoirs are 450m !!. The North Field, was discovered in first joint venture - Petronas, Shell BV and in Middle to Late Miocene predominantly gas 1971 by the completion of Shell’s North West Mitsubishi), 3 to MLNG Dua and 2 to MLNG bearing pinnacle reefs. The reefs were buried Dome-1 well, while the South Pars Field was Tiga. The 8 production trains have a total by fine clastics of the Baram delta complex. discovered in 1990 by the National Iranian Oil liquefaction capacity of 1.2 Tcf/y following the Company (NIOC). debottlenecking completed at the end of 2010 Malaysia’s natural gas production has at the Dua plant. The Bintulu complex also risen over the past two decades to serve Qatargas produces LNG from its 4 ventures hosts Shell’s GTL project, which converts the growing domestic demand and export (Qatargas I-IV). Qatargas I operates 3 LNG natural gas into nearly 15,000 bbl/d of liquids. contracts. Recent foreign investment in trains with a capacity to produce 9.6 mtpa for Addition of the 9th LNG Train, expected in deep water and technically challenging fields Japan and Spain markets. The shareholders 2016, will add another 3.6 mtpa to the existing primarily in the Sarawak and Sabah provides are Qatar Petroleum, ExxonMobil, Total, 25.7 mtpa production capacity. impetus to maintain natural gas production Mitsui and Marubeni. Qatargas II, operates levels over the next few years. These gas 2 trains with a total capacity of 15.6 mtpa. In addition to the Bintulu LNG complex, projects could maintain and ensure the gas It is a joint venture of Qatar Petroleum and Malaysia has two FLNG vessels under production to the Bintulu LNG plants. In 2009 ExxonMobil and supplies 20% of UK’s LNG construction in order to monetise smaller gas Murphy Oil announced the startup of several needs. Qatargas III, a joint venture between assets. The first is Petronas’ FLNG project, smaller new gas fields located in Blocks Qatar Petroleum, ConocoPhillips and Mitsui located offshore Sarawak, which will have SK309 and SK311. The Sarawak Gas Project, operates 1 train with a capacity of 7.8 mtpa; a capacity of 58 Bcf/y. The final investment located 137 miles offshore Sarawak, contains while Qatargas IV is a joint venture between decision (FID) was made in 2012, and the a cluster of fields that are being developed as Qatar Petroleum and Royal Dutch Shell. project is scheduled to commence by the part of a multi-phase project to supply gas to

29 SPE Java . Jan - Feb ‘14 the Bintulu LNG Terminal. Gas sales from the East Upthrown Canyon (KBB Cluster) in the term contracts. Other key consumers include fields are currently 250 MMcf/d. northwest Sabah state. The Kebabangan field China, South Korea, and Taiwan. is estimated to hold 2 Tcf of gas. Production Newfield Exploration in partnership with for KBB is expected to begin in 2014. The country has become a leading LNG Petronas and Mitsubishi made a significant exporter in the Asia-Pacific region in the gasunit basis, discovery and inChevron's its SK-310 Gorgon PSC LNG offshore project Australia cited cost increases of over 40 percent in U.S.past dollar decade. Greater expected natural gas Sarawakterms, from in US$37 2013. The billion company to US$52 claims billion. the In 2012 Australia exported 20.8 mtpa of LNG, production and LNG capacity in the next find could boost gas resources by 1.5 to 3 an increase of 1.6 mtpa from previous year several years is likely to boost gas exports Tcf.Some of the economic and resource constraintsthrough have thecaused addition several of a newly equity commissioned partners to prioritize even their more, particularly for the growing project portfolio stakes and exit some projects.Pluto Also, LNGsome project.neighboring Australia projects is face the thirdcompetition market from in China. Over the past decade, Theeach other Kebabangan for contracted Petroleum gas supply. Operating In a high-costlargest environment, LNG exporter companies in the world are behindbeginning Australian to target LNG exports have increased Companytheir investments (KPOC), towards a consortium projects consisting in more advanced Qatar stages and Malaysia. and could Australia shift more exports focus gas to expansionnearly threeof times, and they are expected facilities versus planning new ones. The floating liquefied natural gas (FLNG) terminal design is less of Petronas, ConocoPhillips and Shell almost exclusively to the Asian market. Japan to rise substantially in the near future with expensive than the cost of an onshore plant in Australia's high-cost environment, and companies have (operator), are developing three contiguous is the primary destination, taking over three- new upstream development and liquefaction proposed several facilities. Prelude LNG, located in the Browse basin off the Northwest coast, could gas and condensate fields including quarters of Australia’s exports in 2012. Most capacity addition. Chinese national oil become the world's first FLNG terminal using a new technology developed by Shell. Kebabangan, Kamunsu East, and Kamunsu of this supply to Japan is covered in long- companies are reported to participate in several Australian liquefaction

Liquefaction terminal Equity partners Status / online date Capacity (Bcf/y) Consumer projects and have signed gas markets purchase agreements to lock Existing facilities in supply with international oil Northwest Shelf LNG Woodside, Shell, BHP Billiton, Existing 780; 5 trains1 Japan, China BP, Chevron, Mitsubishi & spot market companies. Mitsui - 16.7% each Darwin LNG ConocoPhillips 57.2%, Santos Existing 170; 1 train Japan and spot 11.4%, Inpex 11.3%, Eni 11%, ma rke t Australia currently has 3 LNG Tepco 6%, Tokyo Gas 3% export facilities with a total Pluto LNG Woodside 90%, Kansai Electric Existing / Expansion 205; 1 train Japan, Malaysia 5%, Tokyo Gas 5% plans are being capacity of almost 1,200 Bcf/y. discussed The largest is North West Shelf

Planned LNG projects LNG, owned and operated by a using traditional gas consortium of Woodside, Shell, Gorgon LNG Chevron, 47.33% ExxonMobil Under construction; 720; 3 trains Long-term BP, Chevron, Japan Australia 25%, Shell 25%, Japanese gas Q1 2015; T4 planned contracts with & electric utilities 2.667% with construction to Japan, Korea LNG, and BHP Billiton. The begin in 2014 China, India, facility has 5 offshore LNG trains Mexico. Spot ma rke t with a total capacity of 780 Bcf/y, Ichthys LNG INPEX 66.07%, Total 30%, Under construction; 400; 2 trains Japan, Taiwan and it relies on natural gas Japanese gas & electric utilities 2017 2.74% supplied from nearby fields in the Wheatstone LNG Chevron 64.14%, Apache 13%, Under construction; 430; 2 trains Japanese North West Shelf (NWS) in the KUFPEC (Kuwait) 7%, Shell 2016 utilities Carnarvon Basin. Darwin LNG, 6.4%, Japanese gas & electric utilities 9.455% operated by the consortium of Prelude LNG Shell 67.5%, Inpex 17.5%, Under construction; 175; 1 floating Japan and Asian ConocoPhillips, Santos, Eni, Kogas 10%, CPC 5% 2017 terminal2 ma rke t s Cash Maple LNG PTTEP (Thailand) 100% 2017 100; 1 floating Potentially INPEX, Tokyo Gas, and Tokyo t e rmina l Thailand Electric (TEPCO) is Australia’s Browse LNG Woodside 31.23%, Shell 2020; Cancelled 576; 3 trains Japan, Taiwan, 26.63%, BP 17.21%, financial investment other Asia second facility. It has one PetroChina 10.23%, Mitsui decision (FID) for production train with capacity 7.35%, Mitsubishi 7.35% onshore facility in 2013, potential of 170 Bcf/y and is supplied floating terminal with natural gas from the Bayu- proposed. Undan field in the Timor Sea. Bonaparte LNG GDF Suez 60%, Santos 40% 2018; FID expected 100-150; 1 N/A 2014 floating terminal Pluto LNG is Australia’s most Scarborough LNG BHP Billiton 50%, ExxonMobil 2020/21; FID 300; 1 floating N/A recent terminal to come online 50% (operator) anticipated 2014/15 t e rmina l Sunrise LNG (Joint Woodside 33.44%, 2017 525; 1 floating N/A in 2012. The terminal is located Development Area- ConocoPhillips 30%, Shell t e rmina l in the Northwest region and Australia and Timor- 26.56%, Osaka Gas 10% Planned CBM to LNG has a capacity of over 200 Queensland Curtis LNG T1: BG 50%, CNOOC 50%; T2: Under construction; 400; 2 trains Chile, Bcf/y. Woodside is discussing BG 97.5%, Tokyo Gas 2.5% 2014 Singapore, Australia Pacific LNG Origin Energy 37.5%, Under construction; 430; 2 trains China and Japan expansion plans for Pluto ConocoPhillips 37.5%, Sinopec mid-2015; Proposed (Kansai Electric) LNG, but difficulties procuring 25% expansion additional gas reserves and rising Gladstone LNG Santos 30%, Petronas 27.5%, Under construction; 375; 2 trains Malaysia and Total 27.5%, Kogas 15% 2015 Korea project costs pose challenges to Fisherman's Landing LNG Ltd 81.11%, CNPC 2016; FID expected 144; 2 trains Potentially CNPC the expansion moving forward. subsidiary 19.89% 2H2013 Arrow LNG Shell 50%, PetroChina 50% 2018; EIS plan 384; 2 trains in China submitted; FID Phase I Australia currently has nearly

30 SPE Java . Jan - Feb ‘14 $200 billion worth of LNG projects under investments for new greenfield projects and which used to be a significant importer of LNG, construction in the coastal or offshore puts some newer proposed projects at risk continuing to turn away more cargoes and Northwest or North Australia and in the of delay or cancellation. The cost increases increasingly rely on domestic unconventional northeastern Queensland region. The country are attributed to a number of factors: gas to meet its energy needs. On the other is on target to overtake Qatar as the world’s labor shortages and resultant high wages, hand, the boom in North American shale gas largest LNG exporter by 2020. Currently, appreciation of the Australian dollar to the has created opportunities to export LNG from there are 7 projects under construction, 3 U.S. dollar since 2009, greater environmental the US and Canada. With higher demand in Queensland and 4 in the basins of the hurdles due to more strict regulations recently, in Asia, and the perception of lower North Northwest coast and offshore. Total current and the remote locations of some projects. American feedstock costs, a new export play capacity under construction is 3 Tcf/y, which A number LNG projects under construction is emerging. Over the past years, there have should enter operations by 2017. There are have experienced cost overruns of between been numerous new LNG project proposals. other projects waiting on regulatory approval 12 and 32 percent from their original FID. Despite, there are a variety of political or FID (final investment decisions), although Ichthys LNG, sanctioned in 2012, currently unwillingness and commercial risks (low these projects are facing competition is the world’s most expensive liquefaction shale gas rates) that will limit output from the because of escalating costs and potential project on a per unit basis, and Chevron’s US. The country has started to move forward overcapacity. Gorgon LNG project cited cost increases of with the Sabine Pass LNG project and have over 40 percent in U.S. dollar terms, from signed several Sales Purchase Agreements. CBM-to-LNG projects have become feasible US$37 billion to US$52 billion. with the sizeable amount of gas reserves Mozambique associated with the coal production. Some of the economic and resource In 2012, Mozambique has emerged as a new Queensland Curtis LNG could become the constraints have caused several equity giant in Natural Gas. More than 100 tcf were world’s first LNG project of this kind, with two partners to prioritize their project portfolio discovered particularly in the offshore Rovuma neighboring projects under construction and stakes and exit some projects. Also, some Basin. This positions Mozambique as a major two others waiting on FID. Even though many neighboring projects face competition from player in the sector over the next decades companies are leveraging the vast CBM each other for contracted gas supply. In and could become the world’s third largest resources in Queensland to convert the fuel to a high-cost environment, companies are exporter of liquefied natural LNG. A number of LNG, CBM projects pose unique challenges to beginning to target their investments towards large MNCs are actively exploring, appraising production. There are typically more hurdles projects in more advanced stages and could and developing their gas discoveries into for environmental approval. Also, CBM wells shift more focus to expansion of facilities LNG projects in Mozambique. Progress produce much less than traditional gas wells versus planning new ones. The floating towards this direction is already underway. and ramp up to peak production over a much liquefied natural gas (FLNG) terminal design Anadarko Petroleum has awarded front-end longer period. is less expensive than the cost of an onshore engineering and design contracts for the plant in Australia’s high-cost environment, construction of its onshore LNG facilities and According to OGJ, Australia had over 43 Tcf of and companies have proposed several offshore installation at Area 1 in the offshore proven natural gas reserves in January 2013, facilities. Prelude LNG, located in the Browse Mozambique. rising 15 Tcf from 2012. In 2011, Geoscience basin off the Northwest coast, could become Australia estimated total economic reserves the world’s first FLNG terminal using a new Eni announced a new giant natural gas at 136 Tcf (103 Tcf traditional natural gas technology developed by Shell. discovery in the eastern part of Area 4, and 33 Tcf of coal bed methane-CBM). Most offshore Mozambique, at the Mamba North of the traditional gas resources (about 92 Brunei East 2 exploration prospect. This is the percent) are located in the North West Shelf Brunei has been a stable and long-term LNG fifth exploration well successfully drilled in (NWS) offshore in the Carnarvon, Browse, exporter to Japan and South Korea from the area. The new discovery adds at least and Bonaparte basins. Also, most of the its 5-train, 950 million cubic feet per day 10 tcf of gas in place to Area 4. This result traditional gas resources are from 10 super- Lumut LNG liquefaction plant, sending out further increases the total potential of the giant fields even though there are nearly about 330 Bcf in 2011. Brunei produced 439 discoveries of Area 4, which is now estimated 500 fields included in the resource count. Bcf of dry natural gas in 2011, mostly from at 70 tcf of gas in place. To commercialize its In addition, Australia also had an estimated Southwest Ampa and other fields associated finds, Eni has signed a Heads of Agreement 437 Tcf of technically recoverable shale gas with oil production. Although domestic gas (HOA) with Anadarko Petroleum Corporation, reserves in 2012, according to an EIA study demand has steadily increased in the past establishing coordinated development of Technically Recoverable Shale Oil and decade, Brunei still exports on average more common natural gas reservoirs and will jointly Shale Gas Resources. These resources are than three-quarters of its output. French oil plan and construct common onshore LNG dispersed throughout the country: the inland company Total made significant gas and liquefaction facilities in the Cabo Delgado Cooper Basin, eastern Maryborough Basin, condensate discoveries in Block B which Province of northern Mozambique. Japan the offshore southwestern Perth Basin, and could bolster Brunei’s gas reserve base and and Mozambique have signed a MoU aimed the northwestern Canning Basin. sustain its production levels. at supplying LNG which allows Japan to diversify away from Australia and Qatar for Australia’s LNG industry faces acute capital USA supplies. cost escalation requiring much larger It is worth mentioning here, United States,

31 SPE Java . Jan - Feb ‘14 Nusantara Regas: Pioneering the First LNG FRSU in Asia Pacific Hendra Jaya, NusantaraRole of Primary Regas Energy for National Electricity In the beginning, it was all about subsidies.

LN generates electricity from various fuels that are sub efficient in terms Pof cost and source mix. Many power National electricity will requires more LNG plants were designed to burn gas as a cleaner alternative to fuel oil, in anticipation of abundant future domestic gas sources. But domestic gas supply in many cities has not materialized, so PLN continues to burn oil fuel. This is economic for PLN due to subsidized fuel prices, but is bad for Indonesia as a net oil importer since 2004.

Oil prices skyrocketed in 2008. This forced PLN and the Government of Indonesia to

quickly act to better manage their fuel mix. Chart 1: Role of Primary Energy for National Electricity SOURCE: PLN Chart 1 shows that PLN plan to replace MFO 1” is a converted LNG Carrier from Golar and HSD with cheaper coal and gas (piped 1 and LNG). The major projects are the Muara A land-based LNG receiving terminal was not Energy. It was built in 1977, has a capacity Karang and Tanjung Priok power plants that recommended, due to uncertainties in land of 125,000m3 of LNG, and can re-gasify 500 support the biggest loads in West Java. Chart clearance, and a longer construction period. mmcfd (~3.8 mtpa) of gas. It is owned by an 2 shows around 400 mmscfd (± 3mtpa) of Indonesian entity, flies an Indonesian flag, additional gas supply is required to replace A sea-based Floating Storage Receiving can be moored onsite for 20 years, and has fuel oil in these two plants. Unit (FSRU) was selected. FSRU is proven 40 years of hull life. The Picture 2 shows the technology that is safe, reliable, easy to setup FSRU installation and in operation. The birth of PT Nusantara Regas and maintain. However, no FSRU exists in and the first ever Asia Pacific LNG the Asia Pacific region. Indonesia needed to Given so many firsts, this was not an easy FSRU pioneer one. project to implement. It required strong leadership and clear vision. Enter Hendra PLN chose LNG as available piped gas volumes On 17 May 2010, PT Nusantara Regas Jaya, previously General Manager of JOB were too low. A consortium agreement to build (PT NR), a joint venture company between Pertamina – Medco Tomori, as President and operate an LNG receiving terminal was Pertamina and PGN, was established to Director of PT NR to work with the competent established on 22 April 2008, followed three develop and run the LNG FSRU to supply directors and staff already in place. days later by the signing of MOU’s for PLNLNG West PLN Java powerSupply Demand plants and other industries in utilization for the domestic market between West Java. Picture 1 shows the location of Ground Breaking occurred in June 2011, and Pertamina, PGN and PLN. the FSRU relative to the Muara Karang power Commercial Operations begun on 1 August plant. 2012.

Power Plant Capacity Gas Req. Gas Supply Balance In October 2010, the Final FSRU Nusantara Regas 1 secured 1.5 mtpa MW BBTUD BBTUD BBTUD Investment Decision was LNG from the Mahakam gas producers, Muara Karang : - Existing 908 made, followed by signing supplying around 200 mmscfd to PLN Muara - Repowering 694 253 110 -180 of the Sales and Purchase Karang, mostly for peak generation. Although

Tanjung Priok : Agreement with Mahakam this represents less than half of its full capacity, - Existing 1,180 - Repowering 743 296 10 -286 gas suppliers and the Gas the FSRU project is saving $ 1.8 million per Sales Agreement with PLN. day in fuel subsidies. T O TA L 549 120 -466 FSRU “Nusantara Regas

32 SPE Java . Jan 2- Feb ‘14 of execution, and close supervision. The team was supervised by at least four bodies: UKP4 (Presidential task force on control of

FSRU development program), Vice President’s LOCATION office, Ministry of State Enterprises, and Ministry of Energy and Mineral Resources. Internally, Hendra needed to manage cultural differences between parent companies Pertamina and PGN, while developing PT

PLN MUARA KARANG NR’s own identity and culture. LOCATION: 5o 58’ 28,920” LS dan 106o 47’ 57,96” BT RADIUS : 2 KM , WATER DEPTH: 22 – 23 M PIPING LENGTH FROM SHORE: 15 KM Given Governmental pressure and Picture 1: FSRU Location involvement, one would think that all parties would be aligned to achieve the same goal. In reality, things were different. Hendra and The Future of LNG FSRU as hubs will serve end users through small team needed to negotiate their way out of cargo ships and even trucks. Several gas license complexity. They identified more Hendra delivered the first FSRU in the sales MOUs have already been exercised. In than 100 different licenses required from Asia-Pacific region on time and without addition, parent company PGN is finding other various stakeholders to produce first gas, and serious incident. This gives confidence to domestic buyers. managed to slim this down to 40+. This is still stakeholders that Indonesia is once again way too many. Such hindrances should be a leading LNG innovation. For Indonesia, having a variety of gas relic of the past bureaucracy. carriers and transporters, such as PT NR, His next focus is to grow PT NR as a profitable PGN, Pertamina Gas, provides security and Hendra identified three keys to success to business. flexibility of gas supply. However, we need build and install the first FSRU in the Asia- further policies to develop the domestic gas Pacific. Firstly, strong leadership with clear Chart 3 below shows there is plenty of West market, and to ensure the players, which are vision was crucial to keep the project on- Java LNG demand for the next 10 years. fully or partially owned by Government, will time and on-budget. Secondly, stakeholder Operation of West Java FSRU at full capacity not suffer adverse effects from competition. communication unified vision and convinced will fulfill gas demand from PLN and for other all parties to remain in the spirit of the project. industries in the Jakarta area, and reduce fuel Wisdom of the Pioneer Thirdly, the ability to earn trust internally and oil subsidies. to build partnerships. Indonesia is well known as a world leader LNG supply is the issue. PT NR currently has in LNG exports, but until now it has never Great voyage ahead for PT NR and for a single source of LNG, which will reduce to “exported” LNG to the domestic market at Indonesia domestic gas. 1.25 mtpa in 2013. Current LNG supply is this scale. Hendra leads a team of capable only sufficient to meet a part of demand from persons but without experience in building LNG PLN Muara Karang. PT NR is working closely receiving terminals. The team compensated with SKMIGAS and PSC’s to double LNG for its lack of capability with hard work, speed supply by the end of 2013. PT NR, as holder of SPA’s and GSA’s, is in position to manage LNG shipments from various sources, which PROJECT UPDATES FSRU Key Term & Installation will reduce dependency on PSC priority and LOKASI FSRT DI TELUK JAKARTA scheduling.

Fuel oil prices are forecast to stay high, so economics of LNG for power generation remain attractive. Nevertheless, the Government and PLN need to further encourage conversion from fuel oil to gas as much as, or perhaps more than, to coal. Gas infrastructure and the LNG FSRU will improve fuel mix flexibility, and increase source sustainability from both • Mooring system consists of 4 mooring dolphins and 4 breasting dolphins • Mooring system consists of 4 mooring dolphins and 4 breasting dolphins domestic and imported LNG. • Mooring dolphins will be equipped with 3 pad-eyes for connecting the mooring lines Source: Golar Energy • • MooringBreastingdolphins dolphinswill be equipped are equippedwith 3 pad -witheyes for 2 connectingpad-eyesthe formooring connectinglines the mooring lines and 3 PT NR plans to grow beyond PLN and power • Breastingfendersdolphins to absorbare equipped the impactwith 2 pad from-eyes LNGCfor connecting the mooring lines and 3 fenders to absorb the generation. Hendra envisions PT NR to • impactThe LNGfrom LNGC carrier calling at the FSRU (side by side mooring)is taken to be maximum 157,000 m3 • The LNG carrier calling at the FSRU (side by side mooring) is taken to be a maximum 157,000 m3 • LNG transfer from LNG carriers via marinized LNG hard arms become a gas hub, whereby additional FSRUs • LNG transfer from LNG carriers via marinized LNG hard arms

33 SPE Java . Jan - Feb ‘14 SengkangMidScaleLNGDevelopment

StewartW.G.Elliott,Chairman,ManagingDirectorandCEOofEWC

EnergyWorldCorporation(EWC)isdevelopingagreenfieldnaturalgasliquefactionfacilityforproducing liquefiednaturalgas(“LNG”)andbuilda2MTPAmodularLNGliquefactionfacility,comprisingfour0.5 MTPAmodularunitsalongwithLNGstoragefacilitieswithaninitial88,000cubicmetertank,logistichub terminal for LNG exportation and related civil and marine infrastructure in South Sulawesi.The SengkangSengkang LNG Project first 0.5 Mid MTPA modularScale unit is expected to become operational in Q4 2014 providedthatallthepermitsandlicensesareinplace.

CapacityofeachLNGtrainis500,000tonsperannumandourequipmentatthesiteissufficientupto2 million tonsLNG per annum subjectDevelopmen to gas availability (this refers to availabilityt of certification on gas reservesandapprovedfurtherPOD). Stewart W. G. Elliott, Chairman, Managing Director and CEO of EWC

OurstrategyistodevelopthegasfieldinphasesaswebuildoutourLNGplant.Ratherthanspend nergy World Corporation (EWC) is (“Wasambo”) gas fields was issued on June ever built in the country, the project faces significantdevelopingcapital a greenfieldexpenditure natural gasto initially2011, howeverprove upup toreserves, this presentwe time,will a usea varietycash from of challengesinitial LNG in obtainingsales. the Eliquefaction facility for producing commercial decision has not been issued relevant permits and licenses, ranging from Majorliquefied difficulties natural gas (“LNG”)sofar andare buildpermits a byand the licenses, Indonesian including authorities. the Despitegas theallocation gas allocation,from landthe clearance,regulator, specialin this port 2 MTPA modular LNG liquefaction facility, long-winding process on the consents and license up to the environmental feasibility. case,comprisingSKKMIGAS four 0.5 MTPAand Ministry modular unitsof Energypermits,and we haveMineral completedResources. the shipmentDue of diligenceWithin the on energythe sectorgas off itself,Ͳtaker consentshas alreadyalong withbeen LNG storagecompleted facilitiessince with anlast allyear majorhowever equipment weincludingare thestill furtherwaiting two forand theirpermits decision.must be obtainedInaddition from variousto variousinitial 88,000permits cubic meterand tank,approvals logistic hubfor thecoldproject, boxes thatthe are nowcompany already onsite.isrequired The institutions,toobtain namelyanoperating SKKMIGAS,license Directoratein terminal for LNG exportation and related civil site construction has shown a very significant General of Oil and Gas and also the Ministry orderand marineto operateinfrastructurethe in SouthSengkang Sulawesi.LNG progress,Project. includingThePlan the layingofDevelopment of foundations ofof theEnergyWalanga, and MineralSampi Resources,ͲSampi, Provincial/and BongeThe Sengkang(“Wasambo”) LNG Projectgas first fields 0.5 MTPAwas forissued the storageonJune tank2011, and coldhowever boxes haveup toLocalthis Government.presenttime, So far weacommercial have identified modular unit is expected to become already been erected. around 60 permits, licenses or consents that decisionoperational hasin Q4not 2014been providedissued that allby thethe Indonesianauthorities.Ontheothermusthand, obtainedthe to secondensure theshipment compliance ofof majorpermits andequipment licenses areincluding in place. thefurtherThe two estimatedcold timetableboxes are for now commercialonsite. theOther project.significant Especially progress for gas allocation,isthe Mineraloperation Resources, of the SengkangProvincial/Local LNG ProjectGovernment. we understoodThe thatjourney SKKMIGAShasbeen (then,very toughsofarhoweveritis siteCapacityconstruction of each LNG andtrain isequipment 500,000 tons deliveriesremains subjecthad totaken certain place,material includingrisks and BPMIGAS)thelaying guidelineoffoundations prioritizes for regionalthe verymuchworthwhile,consideringthatifwecoulddemonstratethatmodularLNGworksinSengkang, storageper annumtank. and our equipment at the site uncertainties, with both usual construction business enterprise (BUMD) as the gas is sufficient up to 2 million tons per annum withoutrisks fordoubt the will outstandingworkin constructionanyother marginaloff-taker gas otherfields than in PLN.Indonesia. Based on the Thesubject estimated to gas availability timetable (this refersfor commercial to program andoperation country risk of in the relation Sengkang to the guidelines,LNG Project we followed remains such subject direction and to availability of certification on gas reserves legal, regulatory and physical environment we even committed the LNG to be sold certainand approved material further POD). risks and uncertainties,of Indonesia. with As both the first usual modular construction LNG domestically risks to PLNfor whichthe hasoutstanding guaranteed construction programandcountryriskinrelationtothelegal,regulatoryandphysicalenvironmentof LNGStorageTank: Our strategy is to develop the gas ConstructionofBoredͲ Indonesia.field in Asphasesthefirst as modular we buildLNG out everinthecountrywearefacingavarietyofchallengeinobtaining theour relevantLNG plant.permits Ratherand thanlicenses, spend rangingfromgasallocation,landclearance,specialportlicenseupto Piles,PileHeadsand environmentalsignificant capital feasibility. expenditureWithin to the energy sector itself, we need to get consents from various BaseSlabCompleted. initially prove up reserves, we will institutions,use cash fromnamely initial LNGSKKMIGAS, sales. DirectorateGeneralofOilandGasandalsotheMinistryofEnergyand

Major difficulties so far are permits and licenses, including the gas allocation from the regulator, in this case, SKKMIGAS and Ministry of Energy and Mineral Resources. Due diligence on the gas off-taker has already been completed since last year however we are still waiting for their decision. Fortunately, on the downstream side, we have obtained temporary business license from Directorate General of Oil and Gas in November 2012. The Plan of Development of the Walanga, Sampi-Sampi, and Bonge LNG Storage Tank: Construction of Bored-Piles, Pile Heads and Base Slab Completed.

34 WHYMODULAR? SPE Java . Jan - Feb ‘14 WewouldliketochallengeconventionalthinkinganddevelopedalowcapitalcostmodularLNGfacility inassociationwithourtechnology,equipmentsuppliersandourstrategicpartners,ChartandSiemens. WehavebroughttogetherChartIndustriesandSiemens,bothdistinguishedglobalplayers,todevelop anefficient,electricdrive,modularLNGsystemthatcanbeusedinavarietyoflocations.Chartwill provideawellprovenandhighlyreliablesinglemixedrefrigerant,andSiemenswillbringinelectricdrive systemswithVariableFrequencyDrive(VFD).TheskidͲmountedmidͲscaleengkangLNGisdesignedto provide a cleaner source of energy for the many small scale power plants in the Eastern part of Indonesia.

TherearebenefitsandadvantagesofModularLNGmodel,amongothers:

x Significantlylowercapitalcostrequirementwithfasterconstruction. x Utilizesequipmentofproventechnologyandhigherefficiency x FlexibilitytoincorporateadditionalmodularLNGtrainstoaddcapacitytotheexistingfacilitytosuit theparticularcharactersofthegivengasfield x Canbedismantledandrelocatedwhenthegasfieldisdepleted x AbilitytoexploitstrandedgasfieldsthatarenotconsideredcommercialviableforconventionalLNG development. ThecomparisonbetweenconventionalandmodularLNGisoutlinedbelow. compared with traditional mechanical compressor drives, including process steam supply, overall thermalefficiencymayreach90%. to allocate the majority of its upcoming power plant in Makassar, South Sulawesi to the use of gas. We use our best effort to abide with the prevailing regulations, yet such delicate matter may rely more on discretion or policy. The journey may have been very tough so far however it is very much worthwhile, considering that if we could demonstrate that modular LNG works in Sengkang, without doubt it will work in any other marginal gas fields in Indonesia.

WHY LNG? In remote locations and islands not served by gas transmission and distribution networks, LNG-based power generation may offer a cost-competitive and environmentally skid-mounted mid-scale Sengkang LNG attractive alternative to conventional solutions is designed to provide a cleaner source of Internally a Cold Box can extend from such as diesel power generation plants. energy for the many small scale power plants housing a single Brazed Aluminum Heat Eastern Indonesia is separated by long Thein the LNGEasterntank part of Indonesia. Exchanger to a complex system of multiple distances or challenging terrains, and when Brazed Aluminum Heat Exchangers there are geographical and environmental AnotherThere are innovation benefits and advantagesEWCbrought of connectedintothis in seriesSengkang and parallel,LNG togetherProject istheconstructionoflargeconcrete barriers and while the small volume of gas to tanks.Modular LNGWe model, have among been others: able to combinewith associated the interconnecting slipforming pipe, technique process into LNG storage construction by be transported make long-distance pipeline • Significantly lower capital cost separation vessels, valves and a complete transmission uneconomical. PLN studies has workingrequirementwith withGTT fasterof construction.France,who developedinstrumentation thepackage.membrane liningusedinmanyoftheLNGvessels. concluded the cost competitiveness of LNG- • Utilizes equipment of proven technology based power generation and invited private and higher efficiency . ELNG sectors to supply LNG for several identified • Flexibility to incorporate additional With the aim of environment-friendly operation power plants that could be served by a mid- modular LNG trains to add capacity to and to achieve substantial energy efficiency, scale LNG plant. the existing facility to suit the particular our modular LNG project willConcrete use the latestFull ContainmentLNGTankswiththe characters of the given gas field. electric drive compression technologymembrane which liningusedinmanyoftheLNGvessels. WHY MODULAR? • Can be dismantled and relocated when gives up to 25 days additional production We would like to challenge conventional the gas field is depleted. each year and alongside produces(1) Post lowerͲtensioned concretewall thinking and developed a low capital cost • Ability to exploit stranded gas fields that greenhouse gas and noise emissions.(2) Reinforcedconcrete modular LNG facility in association with our are not considered commercial viable The following are the economic benefits of technology, equipment suppliers and our for conventional LNG development. E-LNG: (3) Membranecontainmentsystem strategic partners, Chart and Siemens. We • Maximize productivity (4) and A suspended asset deckmadeofaluminiumand have brought together Chart Industries and The comparison between conventional and utilization Siemens, both distinguished global players, modular LNG is outlined below. • LNG Production is not impactedcovered by byglasswool to develop an efficient, electric drive, modular ambient temperature swings(5) Carbonsteellinercoverstheinnersurfaceof LNG system that can be used in a variety of Mid-Scale LNG Train • Short recovery times after forced outages locations. Chart will provide a well proven and Chart provides the Cold Box, which is of compression plant thedomeroof highly reliable single mixed refrigerant, and externally is a carbon steel enclosure with • Optimize the process plant(6) size Thermal to market protectionsystem Siemens will bring in electric drive systems flanged terminations to facilitate simple on- demand with Variable Frequency Drive (VFD). The site connection to plant process pipework. • An electrically driven LNG facility requires less maintenance when compared to a Conventional EWC’sModularLNGTrainConfiguration gas turbine driven compressor solution.

HighlyscalablemidͲscaleLNGfacilityincorporatedin LargeͲscaleLNGfacilityof4MTPAorabove UPSTREAMSTATUS The design concept of an electrical LNG 0.5MTPALNGtrains Furthermore,EnergyEquityEpic(Sengkang)plant aims to ensurePtyLtd, up tothe 365block days operator, of drilledfourdevelopmentwells CapitalcostaboutUS$125Ͳ150millionper0.5MTPA uninterrupted refrigeration-gas circulation CapitalcostcurrentlyinexcessofUS$3billion (excludingprimarygasprocessingplantandpower generation)in 2013. This drilling campaignorresulted for periods in notgas limited discoveries by either thecontain significant reserves. Natural gas power plant or compressor strings. Even 4.8TCForabovecertifiedprovenreserves production from WalangaͲ2, WalangaͲ3, and WalangaͲ1 is expected to reach approximately 100 Requiresonly25BCFperyear typicallytaking5yearstoconclude including distribution losses, electrical mmscf/dfromtheTacipiFormationsystemswhich achieveas 96%the efficiencyprimary , resultingreservoir. in Thisisalreadybeyondproduction Banksusuallyrequirea20yearsoffͲtake A5yearsoffͲtakecontractcanbeconsideredas overall refrigeration system efficiency of up contractinplacetoprovidefinancing standardtarget of70mmscf/d,asrequiredundertheapproveddevelopmentplanfortheWasambogasfieldsto to 45%, compared with 32% for traditional Nickelsteelirontanks Advancedsupplyfullcontainmentthefirstmembranetrainoftanksgas liquefactionmechanicalplant drive solutions.0.5million Combined-cycletonper annum.Theaforesaidthreesuccessful power plants also reduce greenhouse gas The comparison between conventional and modularwells LNG were drilled withinthe Walanga Structure and proved 110 BCF gas reserves, andthisdoes not

MidͲScaleLNGTrain ChartprovidestheColdBox,whichisexternallyisacarbonsteelenclosurewithflangedterminationsto facilitatesimpleonͲsiteconnection toplantprocess pipework.InternallyaColdBoxcan extendfrom 35 housingasingleBrazedAluminumHeatExchangertoacomplexsystemofmultipleBrazedAluminum SPE Java . Jan - Feb ‘14 Heat Exchangers connected in series and parallel, together with associated interconnecting pipe, processseparationvessels,valvesandacompleteinstrumentationpackage.

ELNG With the aim of environmentͲfriendly operation and to achieve substantial energy efficiency, our modularLNGprojectwillusethelatestelectricdrivecompressiontechnologywhichgivesupto25days additionalproductioneachyearandalongsideproduceslowergreenhousegasandnoiseemissions.

ThefollowingaretheeconomicbenefitsofEͲLNG: x Maximizeproductivityandassetutilization x LNGProductionisnotimpactedbyambienttemperatureswings x Shortrecoverytimesafterforcedoutagesofcompressionplant x Optimizetheprocessplantsizetomarketdemand x Anelectricallydriven LNGfacilityrequireslessmaintenancewhencomparedtoagas turbine drivencompressorsolution.

The design concept of an electrical LNG plant aims to ensure up to 365 days of uninterrupted refrigerationͲgascirculationorforperiodsnotlimitedbyeitherthepowerplantorcompressorstrings. Even including distribution losses, electrical systems achieve 96% efficiency , resulting in overall refrigeration system efficiency of up to 45%, compared with 32% for traditional mechanical drive solutions.CombinedͲcycle power plants also reduce greenhouse gas emissions by around 30% compared with traditional mechanical compressor drives, including process steam supply, overall thermalefficiencymayreach90%.

TheLNGtank AnotherinnovationEWCbroughtintothisSengkangLNGProjectistheconstructionoflargeconcrete tanks.We have been able to combine the slipforming technique into LNG storage construction by workingwithGTTofFrance,whodevelopedthemembraneliningusedinmanyoftheLNGvessels.

ConcreteFullContainmentLNGTankswiththe The four specific areas of interest covered membraneliningusedinmanyoftheLNGvessels. by the seismic acquisition were: Walanga, (1) PostͲtensionedconcretewall Tosora, Salubulo, and Minyak Tanah (2) Reinforcedconcrete Prospects. Pre Stack Time Migration Data (3) Membranecontainmentsystem of SEGY data showed fair reefal build ups, (4) Asuspendeddeckmadeofaluminiumand denoted specific characteristics of the Tacipi coveredbyglasswool Formation as the primary reservoir target (5) Carbonsteellinercoverstheinnersurfaceof thedomeroof in Sengkang Basin. These reefals features (6) Thermalprotectionsystem consist of many standard characteristic of reef, high interval velocity within the reef, diffraction at the edges, drape over the reef emissions by around 30% compared with 2D land seismic acquisition survey was of shallower events, and a lack of events traditionalUPSTREAM STATUS mechanical compressor drives, programmed, executed and completed. within the reefal features. Furthermore,EnergyEquityEpic(Sengkang)PtyLtd,theblockoperator,drilledfourdevelopmentwells including process steam supply, overall The Survey covered all target areas of the in 2013.This drilling campaign resulted in gas discoveries contain significant reserves. Natural gas thermalproduction efficiency from Walanga may reachͲ2, Walanga 90%. Ͳ3, and WalangaSengkangͲ1 is expected Block to and reach was approximately completed 100 on The main purpose of the 2D seismic mmscf/dfromtheTacipiFormationwhichastheprimaryschedule,reservoir. withinThis budget,isalready nobeyond reportableproduction social acquisition basically was to infill data in the Thetarget LNGof70 mmscf/d,tank asrequiredundertheapprovedproblemsdevelopment andplan incidents.fortheWasambogasfieldsto most interesting prospective areas. Tighter Anothersupplythe innovationfirsttrainof EWCgasliquefaction brought plant into this0.5million tonperannum.Theaforesaidthreesuccessful grids seismic data will be helpful to conduct Sengkangwells were LNGdrilled Project within theis the Walanga construction Structure of andThis proved 2D 110 seismic BCF gas program reserves, acquired andthis ordoes 99.8% not an advanced subsurface analysis. The large concrete tanks. We have been able to 220 km in length and consist of 3554 shot additional data have prompted increasing combine the slipforming technique into LNG points and covered the four separated sub- optimistic enthusiasm of the volume gas storage construction by working with GTT of blocks which were considered geologically resources on Sengkang Block and have France, who developed the membrane lining prospective. The survey commenced on estimated more than 600 BCF Most Probable used in many of the LNG vessels. December 15th, 2012 and was completed (P50) gas resources from major prospects. on April 12th, 2013 without any safety, social Unexpected prospect was identified from the UPSTREAM STATUS and environment incidents. newly acquired data, and is named North Furthermore, Energy Equity Epic (Sengkang) Minyak Tanah. The location of this prospect is Pty Ltd, the block operator, drilled four The acquisition will enable interpretation in the southernmost part of Sengkang Block development wells in 2013. This drilling based on adequate high resolution where the subsurface image display very fair campaign resulted in gas discoveries contain subsurface images thereafter reducing reefal build up and the crest is in a shallow significant reserves. Natural gas production uncertainties during the exploration and depth of approximately only 250 meters or from Walanga-2, Walanga-3, and Walanga-1 development stages within Sengkang Block. 820 feet. Our quick calculation has estimated is expected to reach approximately 100 This endeavor represents a significant step that the gas resource is 135 BSCF. mmscf/d from the Tacipi Formation which as in the Company’s commitment to continue the primary reservoir. This is already beyond exploration activities within Sengkang Block Processing of the 2D Seismic Data has production target of 70 mmscf/d, as required includeto gain a the better Sampi understanding Structure the specific yet, whichcommenced has ina lateone August well 2013 drilling and theprogram. The SampiͲsampiͲ1 will be under the approved development plan for the completedareas of interestin early that can2014 be targetedandwe foranticipate data was availableanother for 26interpretationBCFproven in late reservesof fromthewell.Additionalgas Wasambo gas fields to supply the first train exploratory drilling and secure additional gas December, 2013. of gas liquefaction plant 0.5 million ton per resourcesresources. areexpectedtocomefromtheSalloBullogasdiscovery. annum. The aforesaid three successful wells were drilled within the Walanga Structure Sengkanggasprocessingplant and proved 110 BCF gas reserves, and this does not include the Sampi Structure yet, which has a one well drilling program. The Sampi-sampi-1 will be completed in early 2014 and we anticipate another 26 BCF proven reserves from the well. Additional gas resources are expected to come from the Sallo Bullo gas discovery.

Considering the new production records from the continued drilling success in Sengkang PSC Block, EWC is assured in seeking to establish a reserve base of about 2 trillion cubic feet of gas, sufficiently to supply a mid-scale LNG of 2 million tons per annum capacity by feeding into the 3 remaining trains which are already on site.

To fully assess the gas fields’ potential, a Sengkang gas processing plant

36 SPE Java . Jan - Feb ‘14 ConsideringthenewproductionrecordsfromthecontinueddrillingsuccessinSengkangPSCBlock,EWC isassuredinseekingtoestablishareservebaseofabout2trillioncubicfeetofgas,sufficientlytosupply amidͲscaleLNGof2milliontonsperannumcapacitybyfeedingintothe3remainingtrainswhichare alreadyonsite.

Tofullyassessthegasfields’potential,a2Dlandseismicacquisitionsurveywasprogrammed,executed and completed. The Survey covered all target areas of the Sengkang Block and was completed on schedule,withinbudget,noreportablesocialproblemsandincidents.

This 2D seismic program acquired or 99.8% 220 km in length and consist of 3554 shot points and covered the four separated subͲblocks which were considered geologically prospective. The survey commencedonDecember15th,2012andwascompletedonApril12th,2013withoutanysafety,social andenvironmentincidents.

The acquisition will enable interpretation based on adequate high resolution subsurface images thereafter reducing uncertainties during the exploration and development stages within Sengkang Block. This endeavor represents a significant step in the Company’s commitment to continue explorationactivitieswithinSengkangBlocktogainabetterunderstandingthespecificareasofinterest thatcanbetargetedforexploratorydrillingandsecureadditionalgasresources.

Thefourspecificareasofinterestcoveredbytheseismicacquisitionwere:Walanga,Tosora,Salubulo, andMinyakTanahProspects.PreStackTimeMigrationDataofSEGYdatashowedfairreefalbuildups, denoted specific characteristics of the Tacipi Formation as the primary reservoir target in Sengkang