YoungPetro - 17th Issue - Spring 2016

SPRING / 2 016

4th annual

18 - 19 May 2016 ILEC Conference Centre, London

Where the UK’s unconventional pioneers meet The UK’s #1 shale conference & exhibition Headline supporter:

Supported by:

Certified by:

www.terrapinn.com/shaleuk2016

Created by:

ditor’s Letter E

3

“Dad, as a good American, believed his newspapers,” wrote Upton Sinclair in his novel Oil! This satire book is larger than life in subject and in themes it includes, which are not only development, technology and disasters but also great victories.

It inspired artists, economists and engineers to create, dream bigger and develop.

In this issue we would like to present to you a variety of topics, which will both entertain you and extend your knowledge. This is especially valuable that during this bearish period in oil and gas industry we still get so many applications from you and we keep in touch with our ambassadors from all around the world. Thanks to one of them, Josiah Wong Siew Kai, we are able to share the experience from OGFEST, which took place in Malaysia, and learn from a highly informative article by Ruban Paramasivam, who won the Postgraduate Paper Presentation Contest there.

During our studies and work we pay attention mostly to technical calculations. Even though an engineer, trust me, is “always” right, mistakes happen, and the only thing we can do is to learn from them. Through fire and flames will bring you closer to a story about one of the biggest catastrophes in the history of European O&G industry. This kind of accidents does not come very often, but when they do the effects can be deadly for the enterprise also because of the public opinion. An article written by Ph.D. Roberto Cantoni will draw your attention to the problem of the lack of communication between the companies and society.

As always, our editor, Radosław Budzowski, has prepared a short note about most significant facts and events that had place in last months.

However, spring is a time of changes and you may have noticed some changes in our editorial team. As a fledgling Editor-in-Chief I am proud to introduce you to the results of our hard work and I hope you will enjoy it!

SPRING / 2016

4

Editor-in-Chief Natalia Krygier n.krygier@youngpetro.org Deputy Editor-in-Chief Maciej Wawrzkowicz m.wawrzkowicz@youngpetro.org Art Director Natalia Rodzińska n.rodzinska@gmail.com Editors Patryk Bijak Filip Czerniawski Agata Gruszczak Wojciech Kurowski Maksymilian Łękowski Alina Malinowska Jakub Pitera Monika Saczyńska Scientific Advisor Tomasz Włodek IT Michał Solarz

Logistics Radosław Budzowski Graphic designer: Patrycja Lanc Proof-readers Adam Sikorski Ambassadors Josiah Wong Siew Kai – Malaysia Alexander Scherff – Germany Tarun Agarwal – India Mostafa Ahmed – Egypt Manjesh Banawara – Canada Rakip Belishaku – Albania Camilo Andres Guerrero–Colombia Moshin Khan – Turkey Ahmed Bilal Choudhry – Pakistan Muhammad Taimur Ashfaq – Pakistan Viorica Sîrghii – Romania Michail Niarchos – Greece Rohit Pal – UPES, India Usman Syed Aslam – India Publisher Fundacja Wiertnictwo - Nafta - Gaz, Nauka i Tradycje Al. Adama Mickiewicza 30/A4 30 - 059 Kraków, Poland www.nafta.agh.edu.pl

Marketing Karolina Zahuta

ISSN 2300 -1259

Published by An Official Publication of

The Society of Petroleum Engineers Student Chapter P o l a n d • www.spe.net.pl

5

On Stream – Latest News

7

Radosław Budzowski

Shale World Europe 2015 10 Karolina Zahuta

The importance of talking to frogs 13 Roberto Cantoni, Ph.D.

Through fire and flames 16 Filip Czerniawski

Downturn never drag me down 20 Josiah Wong Siew Kai

Global LNG Market: Trends and Future Outlook 22 Athanasios Pitatzis, M.Sc.

Strategies in addressing obsolescence on the subsea control 30 systems for deep offshore field developments Riverson Oppong, M.Sc.

Nanomaterial additive in oil based mud 39 for high temperature condition Ruban Paramasivam

Methane hydrates – the new energy source? 53 Patrycja Lanc

Achimov Gas – Condensate Production 61 Benjamin Bosbach, Georg Lingenfelder, Joschka Röth, Fabian Tillmans, Marco van Veen

Radosław Budzowski

7

 On Stream – Latest News Radosław Budzowski Poland wants to participate in LNG projects in Iran and import the Iranian oil

After the lifting of sanctions imposed on Iran, Tehran is looking for investors who could invest in the oil and gas sector. Western countries, including Poland, are interested in the acquisition of shares in attractive Iranian oil and gas fields.

In March, there was a visit of Polish economic mission in Iran. The organizer of the four-day visit was the Polish Ministry of Development.

After the abolition of most of the commercial and financial sanctions Iran is becoming one of the most important markets in the Middle East region. Poland is interested in participating in LNG projects in Iran, as well as in purchasing crude oil. Polish companies also expressed their willingness and readiness to engage in Iranian upstream and downstream oil sectors. Hossein Esmaeili, General Director for Europe, America and the Caspian Sea in the Ministry of Oil Industry, said that Poland is interested in diversification of its energy sources. It is worth noting that currently Poland imports 90% of its demand for oil and 60% for gas from Russia.

Will Serbia join the Southern Gas Corridor?

Serbia has a huge potential to work with Azerbaijan in the energy sector – said the former Serbian president, Boris Tadic. He noted that during his presidency, he had contributed to closer cooperation between Serbia and Azerbaijan. The former

Serbian leader also noted how important the role that Baku plays in energy sector is. “Last year, we signed with Azerbaijan an agreement on strategic partnership. In Serbia, many Azeri companies lead its activity. But we also have great potential to cooperate in the energy sector. I wish Serbia would join the Southern Gas Corridor” – said Tadic. The current Serbian leader Tomislav Nikolic in an interview to Russian media said that he believes in the implementation of the South Stream gas pipeline project. “I think I never lose hope that we will be able to implement the South Stream. Judging by how the situation in the European Union is developing and how often they are violates its own law, I begin to hope that perhaps the EU abandons its rules that prevent the construction of South Stream” – said Nikolic.

In May, the experts will assess the profitability of Russia-India gas pipeline

Russian Izvestia announces that in May discussions on the possibility of building a gas pipeline from Russia to India will begin. RIA Novosti reported that in May this year the meeting of the joint working group is being held in New Delhi, and during the meeting the prospects of such a project will be discussed. A meeting with our Indian partners created an opportunity to build such infrastructure. Next meeting will be held in May in New Delhi, where we will discuss the ten selected options of project implementation.

Finally, our arrangements will confirm or exclude the profitability of the project. 

SPRING / 2016



8

Find us on Facebook facebook.com/YoungPetro

9

For online version of the magazine and news visit us at youngpetro.org

SPRING / 2016



Shale World Europe 2015

10



Shale World Europe 2015 Karolina Zahuta

On 17­t h–18th of November 2015 in Warsaw, the 6th annual Shale World Europe conference took place. The presentations tackled valuable topics such as differences in type of shale gas resources in various parts of the world. The Chinese, British and European (especially Polish) shales were mentioned. The considerations were of how it could be exploited, what the approach of the society is, what the geological conditions are, what the process of getting licenses is, etc.

Moreover, several companies presented their business profiles and their actual position in the shale gas industry. During this two-day event the speakers presented their materials and answered the questions from the audience.

General overwiev of the situation in Europe

It started with a keynote panel What level of success does Europe need to make shale dreams a reality?

Dr Georgii Rudko, Head of State Commission on Mineral Reserves in Ukraine talked about the prospective regions of Ukraine. He pointed out that the taxation scheme is preventing a potential activity. Dr Attila Nyikos said that in Hungary oil and gas prices had shrunk and they would not get better within the next 2–3 years. There will be time when mainly shale gas reservoirs are available so sooner or later we should start to exploit them. Besides, European conventional sources are running out – now it’s the best time for research programmes. It creates a global competition for investment. Troy Wagner from BNK Polska said that the prices of oil in Poland are high. It creates an opportunity for governments to use shale more efficiently. Greame Mackenzie presented a Spanish prospect – their gas price is similar to Polish’s.

Spain does not rush for drilling.

The key issue is to help develop – geology in Europe is different than for example in the USA .

There was a comparison of Polish and West Ukrainian shales to Chinese (Sichuan). Both Poland and Ukrain have a different approach than China has. Apart from technical, political and environmental issues, Ukraine has also military problems, which complicates the matter more.

Mike Bradshaw, Professor of Global Energy (Warwick Business School), said that we should turn resources into an opportunity. The governments need to be more realistic with their taxation requirements. Next thing is related with public perception – in the US it is not a problem to carry out any operation in a densely populated area, e.g.: in the middle of airport grounds, while in Europe it wouldn’t be possible. For example, in Oklahoma City, there are three airports – Will Rogers World Airport and two general aviation-corporate airports – that together have 87 active wells, which generated more than $2.5 million in revenue in 2013. Several oil rigs, some of them pumping, can be spotted by passengers from the airfield.

Another theme was the resource-based petroleum complex of Ukraine and the prospects for its development. Dr Georgii Rudko presented general information about the historic and present petroleum industry of Ukraine. He said that as of today most of the deposits are at the final stage of their development. There are 3 major prospective areas for unconventional gas production: the Eastern with 228 hydrocarbons deposits, the Western with 122 and the Southern with 45 deposits. The hydrocarbons reserves for 2014 in Ukraine were of about 993.3 bcm of natural gas and 60.3 million tons of gas condensate. Since 2005 there has been a constant

Karolina Zahuta

decrease in drilling. For example – Chevron left Ukraine (and Poland). It’s because of the demand for large start-up investments (as in the case of the Oleska prospective area). Cutting taxes would be really helpful in this situation as well.

Public misconception

Michał Gronert from DNV GL talked about the risk management of shale gas developments.

According to what he said, flexible energy sources are necessary to fill in for the renewables. There is no scenario without the hydrocarbons in the future. The source of public misconception about fracking is a result of differences in approaches

11

between the operators and people who live nearby the potential or active places of output. It is a fact that the process of exploitation changes the landscape; there are also the installation and transportation aspects. It behoves the operator to demonstrate that that the operation he is going to perform is safe and sustainable. The conclusion is that the local community’s and investor’s points of view should be unified. The problem is presented in more detail in a humoristic way by Roberto Cantoni in the article “The importance of talking to frogs” in this issue of YoungPetro.

The question of whether the Polish shale is dead appeared as well. Troy Wagner from BNK Polska

SPRING / 2016





12

said it isn’t. There were various expectations related to it – each researcher forecasted different resources, which varied from very limited to extremely abundant.

Bringing closer the UK’s shales

Mike Bradshaw discussed the shale situation in the UK . He said that despite the fact there was strong political support from the central government, there was too little progress. He quoted the statement of the Energy Secretary Amber Rudd addressed to the parliament in September in which she said that the government considered that there was “a clear need to seize the opportunity now to explore and test our shale potential.”

There is no denying – it is a hot topic, everybody awaits the situation to develop. As of today there have been a lot of reports about shale in the UK .

It is worth emphasising that the UK has one well drilled while there should be about 1200 drilled within the next 20 years. In the Preese Hall 1 well, the UK’s only hydraulically-fractured shale gas well (till November 2014), drilled by Cuadrilla Resources, there was poor cementation in the horizontal production zone only. That may

Shale World Europe 2015

compromise the productivity of the well, but would not pose a leak or safety issue. Basing on a survey, the number of people who say “no” to the shale gas extraction is growing. We should be aware that what actually stands behind the social license is the local license. A closer, fresh look on shale in the UK will be presented this summer in London during the Shale World UK 2016.

How can it be improved?

Summing up, how can we solve the problems?

No matter which part of the world we choose, technology needs to be localized and the companies need to be prepared to involve themselves in a long-term relationship when it comes to investing and exploiting shales. At the Shale Gas World 2015, a group of professionals and people linked with the industry created a summative point at the end of the year for the current shale situation. This topic is of course much more elaborate, it contains a whole range of issues – geological, technical, engineerical, sociological etc., because there are a lot of ways to approach it. Another significant event – Shale World UK 2016 – is approaching and it is going to take place in London in May. It will show whether something has moved forward or not. 

References: 1. http://www.cnbc.com/2014/04/07/gushing-over-oil-and-natural-gas-drilling-at-airports.html 2. https://www.gov.uk/government/speeches/amber-rudds-speech-on-a-new-direction-for-uk-energypolicy 3. https://en.wikipedia.org/wiki/Hydraulic_fracturing_in_the_United_Kingdom

Roberto Cantoni, Ph.D.

 The

13

importance of talking to frogs

Roberto Cantoni, Ph.D.

**LATTS, École des Ponts ParisTech ÞÞFrance roberto.cantoni@enpc.fr  University  Country  E-mail In mid-January The Italian Constitutional Court approved a call for a referendum against offshore drilling in the Adriatic Sea. The aim of the referendum, which was put forward by 10 of the 20 Italian regions, is to oppose the Italian national government’s decision to assign exploration concessions in the sea off the Tremiti Islands in the country’s south-east. In a way, it is a result of the government’s and the oil industry’s neglect of consultation with local administrations and communities, and could mean an end to oil operations in that region.

Could this have been different? A story of ponds and frogs may help clarify the matter.

“One does not warn frogs when one is about to drain a pond.” This sentence, uttered in 1986 by one of the directors of France’s main power companies, EDF, in the aftermath of the Chernobyl accident in Ukraine, has become paradigmatic of the attitude of techno-scientific circles towards the citizens of communities affected by industrial projects.

Frogs are of course the citizens, and those who should not warn them are the engineers. Why not warning frogs? Firstly, because they do not understand human language. Secondly, because even if they did, and if one warned them, they would go hysterical and start jumping all over the place, perhaps up to the engineers’ faces, and thus disturb the draining procedures. Therefore, if you do not warn the frogs, you can be sure that the implementation of your project will speed up

and the sooner the project is finished, the more efficient the company will prove to be.

What about the frogs? They will perhaps find another pond to swim in or, if they do not, they will die. However, metaphors aside, frogs are the allegory of people who enjoy the same rights as the draining engineers, so the situation is quite more complicated (besides, many would argue that even if the metaphorical frogs were real ones, you would still have to take care of them). What happens then if you do not bother to warn the frogs (vel. people)?

Let us make a thought experiment, the one that early quantum physicists liked to make. Let us suppose, for the sake of the readers’ familiarity with the subject, that an oil company has asked the government of State X for a concession in an onshore region of that state. At this point, most states in Europe would do what the Italian government has recently done for the Adriatic Sea concession mentioned in the opening: address the National Geological Institute, the Oil and Reservoir Engineering Institute, and perhaps a couple of environmental engineers, to give a technical opinion. Let us say the opinion is positive and the company is assigned the requested concession. One day, the company’s trucks arrive at the prospective exploration site.

And here the problems start. To make it short, as soon as the trucks arrive, people start to get rather anxious – similarly as you would feel, if you woke up one day and found someone unexpected in your house. The locals may assert that they should not bear the responsibility and pay the price for the environmental impact or disruption of their lives and habits because of the new industrial activity. Therefore, they may, for example, decide

SPRING / 2016





14

to impede the company’s works. How would you convince them that not only you do not mean to harm them, but also that, on the contrary, the activity your company is developing is going to bring around such benefits as jobs or revenues?

Well, at that point it is probably already too late. If you want to be welcomed at a house, you ring the bell before entering it, not after it. But let us suppose the community is still open to listen to your reasons (and that the national government does not simply resort to police to end any opposition by sheer force). You will then face a problem of language: better said, of communication. Formally, you both speak, say, the same language, but you are talking in terms of statistical probability of risk, financial benefits, industrial grandeur of the nation, whereas the town’s mayor and his or her experts may be talking about preservation of cultural values, environmental harmony, cows and herons. The mayor may not be necessarily interested in economic cost-benefit analysis, and may argue that there are aspects the financial value of which cannot be estimated.

Even though he may be acquiescing in your language, he will oppose by using his own technical counter-expertise or by calling upon the help of other techno-scientists to support the community’s opposition (this is what happened, for example, in the case of shale gas developments in the village of Żurawlów, in Lublin voivodeship in Poland). Your company’s attitude and your own, in that case, could make a difference. You know that societies do not work like corporations: rules are different, values too. If you try to impose your company’s will in an aggressive way… that is, if you assume you have got free hands only because the government has given the company a concession, and because you are faced with a bunch of people who are uttering what you consider unscientifically-based, or scientifically-mistaken, nonsense… then you have lost the game. People will see it, and counteract in response. I am obviously not suggesting being hypocritical and seek to patronize the local community’s representatives

The importance of talking to frogs

– who, incidentally, may not want to be patronized at all – but you should understand that technical arguments may be as valid as non-technical ones when it comes to making decisions on industrial activities. Sure, it is also a rhetoric battle, but it does not just boil down to that.

But let us move on to the second problem regarding our “frogs”: if you warn them, they will get hysterical. It may be true; however, this argument is ill-formulated. The point here is not about “warning,” but about “negotiating.” It is a completely different matter. If you warn someone, it means you have made a decision and you are communicating it to someone else. But this “someone else” has no say in your decision. “Warning” means that you are going to do something, and the others will have to prepare for the consequences of your action; but they cannot avoid the action itself. The thing is that in contemporary Europe “warning” does no longer work. It may have worked in the 1950s Western Europe, or in the Communist Eastern Europe, when scientists were considered godlike figures and states would crush any opposition without major consequences. Nowadays, however, “warning” generates enduring opposition and confrontational attitudes, including a wide range of modalities going from petitions to physical destruction of machineries. And that may fatally jeopardize any industrial activity, be it building a nuclear plant, fracking a shale gas well, or setting up a wind power station. Not to speak of the impact that one mobilisation can have on other parts of the country, or the whole continent (as controversies about shale gas or nuclear power plants have shown). Essentially, “warning” is proper to technocracy, Cold War-style. What is then proper to democracy? Negotiating.

Negotiating is synonymous with co-production of knowledge. It does not take a lexicographer to argue that if you are negotiating with someone, you are expressing your view, listening to your interlocutor, and trying to come to a solution.

None of you should be convinced that one of you holds the ultimate “truth,” though you may be

Roberto Cantoni, Ph.D.

convinced to have powerful arguments to support your view. Nevertheless, your interlocutor or you may have underestimated or overestimated some aspects, and negotiation’s role is to help it to come out. Again, negotiations should precede trucks, since no one likes to negotiate from a position of weakness: an example of that are the round table talks on shale gas extraction (razemolupkach.pl), organised in the Pomerania region in Poland. In this case, representatives of the local communities, oil companies, NGOs, the government, and sociologists, have gathered on a number of occasions to talk about the opportunities and challenges brought about by shale gas. However, the round

15

table talks were organised after the industry had already started operations in the region, which led many activists and members of the collectivities to look at the experiment – otherwise a very laudable initiative in participatory democracy – as a set-up to save appearances.

Negotiating may be long, bitter, harsh, and may ultimately even lead to failure, that is, to communities’ rejecting an industrial plan. But if we want to extend our concept of democratic ruling, and involve the largest possible number of citizens in that process, then I believe there is no other way to go. We have to learn to talk to frogs. 

SPRING / 2016





Through fire and flames

16



Through fire and flames Filip Czerniawski

**AGH University of Science and Technology ÞÞPoland f.czerniawski@youngpetro.org  University  Country  E-mail This will be a story about one of the biggest crude oil eruptions in the history of Europe. Karlino, near Koszalin in Western Pomerania, is the place where one of the most unexpected incidents in history of drilling in Poland happened. December 1980, operation in drilling rig as aimed to reach 4100 meters. Its task was to find further reserves of natural

gas in the sediments of the Lower Carboniferous.

The analysis of the drilling sections of Karlino-1, as well as the previous ones in Pomerania, pointed out that the roof of Zechstein may be separated by over 100 meters from the Main Dolomite roof. If so, oil and gas should be located at the depth of 2850 metres, at the shallowest. What really happened is that having reached 2779 metres on 9th December, the drilling crew got into the drift roof of the Main Dolomite, which contained oil and gas at very high pressure. At around six p.m., due to the leakage of a protection device, a rapid flow of crude oil and natural gas occurred. The flames reached the height of 60 metres!

Filip Czerniawski

17

SPRING / 2016





18

It was definitely the biggest crude oil eruption in Europe. People had to face the problem and, to be honest, no one was prepared for the situation.

The media informed about the outbreak in a very outlandish way. The news were very positive and hopeful that Poland would then flourish as a new crude oil giant. Some people even used the phrase ‘Polish Kuwait.’

At first, only local firefighters tried to face the fire, though after a few moments they realized that they needed more people to get rid of the problem. The flames were spreading and in the close neighbourhood of drilling rig here were

situated barracks with flammable gases. The first task was to secure these buildings to prevent further explosions. When the situation got tough, the firefighters had to carry out the gas bottles with their bare hands. Every container weighted approximately 70 kilos!

During that time the temperature in Western Pomerania was of about -15 °C, yet heat from the fire was so intense that some flowers and trees started to blossom. After a few days, when the closest surroundings were secured, there was time to think about a strategy. When a few specialists from the USSR and Hungary came to Karlino, the

Through fire and flames

whole team was ready to put out the fire. One of the helpers from abroad was Leonid Kałyna. He was in charge during the operation. The idea was to use military machines with MIG -21 jet engines on top to extinguish the fire with an enormous impetus of wind from the engines combined with water pumps located around the eruption.

That was a mistake. Without the fire, whole area had been covered with crude oil in a moment. The commander decided to ignite Daszewo-1 again and the team had to face the fire again. From that moment though, people understood that it was only a matter of time to finish this crisis once and

for all. On 10th January 1981, a month after the explosion, the fire was put out for the last time and a rapid flow of crude oil was tamed by a new blowout preventer imported from Romania.

A week after the dramatic operation, the exploitation started. The eruption made Karlino famous for a while. A lot of people wanted to hear the story. Unfortunately, in 1983, the oil exploitation was stopped because of small efficiency of the layer. The eruption that lasted for a month raddled huge amounts of oil. Media were wrong: Poland did not meet requirements to become another Kuwait… 

Filip Czerniawski

19

References: 1. Górecki M. (2013, March) Szejk (107): Jedyny na pomorzu pp. 9, Karlino, Poland.

2. Głąbiński Z. (2014) The science and technology Centre „Energy” in Karlino- the project of a new geotourist attraction in western Pomerania. Szczecin, Poland.

3. Lercher R. (1981) Karlińska batalia, Wydawnictwo MON. 4. Łukasiewicz K. (2001) Karlino, Omega Bydgoszcz.

5. Czasnojć M. (2012, May 6) 32 lata temu w Karlinie. from: www.albumpolski.pl/artykul/32-lata-temuw-karlinie 6. Author unknown. (November 2013) Erupcja ropy from: www.karlino.pl/strona-550-erupcja_ropy.html

SPRING / 2016





Downturn never drag me down

20



Downturn never drag me down Josiah Wong Siew Kai

**Universiti Teknologi Malaysia ÞÞMalaysia mst.seefi@yahoo.com  University  Country  E-mail The Oil and Gas Festival 2015, also known as OGFEST ’15, is the grandest biennial event organized by the Society of Petroleum Engineers UTM Student Chapter (SPE-UTM-SC) and it was held on 16th and 17th November 2015. This event aims to unlock the next level of students’ creative and innovative ideas in oil- and gas-related field, as well as to expose them to the need to develop new technologies, especially in this unconventional era. With a felicitous theme of “Diversification and Innovation Towards Unconventional Era,” this two-day event, gathering oil and gas companies from various backgrounds in one place, gave students an invaluable opportunity to obtain information and clarify any doubts with the respective companies.

Oil price slump; what can students expect in the long run?

With oil prices fluctuating between $35-$45 per barrel for the past few months and expected to stay at this level for a long period, oil exploration and production activities are expected to reduce and, thus, lead to the decrease in job opportunities in the oil and gas industry. Students who are currently enrolled in courses which cater to this particular industry are worried about what is going to happen next. Pieces of advice and, more importantly, professional insight have to be gained from senior students as well as the people who

are already plying their trade in the industry. The director of OGFEST’15, Mr. Sivanyanam Ravinttiran, said that the objective of this festival is to help unleash students’ creative and innovative ideas in the oil and gas related field, as well as exposing them to awareness of the need to design and develop new technologies for the use of the industry.

This grand event was officiated by Yang Berhormat Datuk Ir. Haji Hasni Bin Haji Mohammad, the chairman of the State Public Works, Rural and Regional Development committee, Johor on Monday morning, 16th November. The sponsors that helped OGFEST ’15 achieve its goals included Casa Armada, Schlumberger WTA Sdn. Bhd. and Talisman Limited. Other companies that helped sponsor this grand event were Murphy Sarawak Oil Company Limited, ConocoPhillips Malaysia, NGC Energy Sdn. Bhd. and ProEight Sdn. Bhd. Competition

The Petrobrain competition, which was sponsored by Schlumberger WTA Sdn. Bhd., was the event that enticed a lot of people on the first and second day. This competition put a team of contestants through their paces on technical and general knowledge related to the oil and gas field. In the competition there were altogether 17 teams competing against each other in goodwill and it got hotter every round! Other competitions included Paper Presentation, Mud Innovation Competition, Oil Rig Competition, Poster Presentation and Petroearth Competition. In Paper Presentation, an undergraduate or postgraduate student would present his or her thesis to a panel of judges. Content, demonstration and oratory skills were important if you wanted the judges to take note of your paper. While in Poster Presentation, each contestant had to design the most creative,

Josiah Wong Siew Kai

easy-to-understand poster with a noteworthy content and present it according to the theme. In Mud Innovation Competition a team would be given two and a half hours to formulate and make a drilling fluid or drilling mud that is suitable for the formation of the given case study. For Oil Rig Competition, a team would construct a model oil rig using the items provided and note all the winning points of their design. In short, they had to sell their design to the judges who were their customers. Petroearth Competition: a recently introduced competition in OGFEST, which is also a quiz, but focuses more on geology.

Exhibition

Exhibition booths were one of the main attractions on that day. Students were able to ask more about the company that they were interested in, and establish a rapport. The tips and pieces of advice given by the companies were very helpful. The exhibitors included Casa Armada, Schlumberger Malaysia, Sherwood Protective Apparel Sdn Bhd., SPIE Oil & Gas Services and many more.

Technical talks, career talks and forum

We are proud to have had VIPs from SPE KL Section to present their talks in our forum, technical talks and also career talks. Also, don't forget our gold sponsor; Schlumberger also delivered an informative speech to our delegates during the forum and career talks.

21

Participants form all around the world

This year, we are proud to announce that we have broken our historical record with more than 219 students from 18 international and 6 local universities participating in the event. Students showed to be more aware of the competitiveness of the industry. They need to be more active and proficient, especially in problem solving and management, since employers are now focusing more on good management and soft skills rather than academic qualification. It provides a platform for engineering students from higher education institutions with an opportunity to showcase their unique opinions addressing any issues that may arise in their professional lives later on. The international universities that joined OGFEST ’15 were Freiberg University of Mining and Technology, Southwest Petroleum University, China University of Petroleum Beijing, China University of Geoscience (Wuhan), Sudan University of Science and Technology, Coventry University, Institut Teknologi Bandung, UPN “Veteran” Yogyakarta, Cairo University, Trisakti University, Institut Teknologi Sepuluh Nopember, Politeknik Brunei, Islamic University of Riau, Institut Teknologi Brunei, Universitas Padjajaran, Universitas Indonesia and Kyoto University. The 4 local universities included our University Technology of Malaysia, University Technology of Petronas, University of Malaya and also University of Nottingham.

NEXT YEAR IN KUALA LUMPUR.



SPRING / 2016





Global LNG Market: Trends and Future Outlook

22



Global LNG Market: Trends and Future Outlook Athanasios Pitatzis, M.Sc.

ÞÞGreece thanospitatzis@hotmail.com  Country  E-mail

In the short term: ÈÈ ÈÈ

The global low LNG prices of the last two years have created a significantly difficult business environment for many LNG exports projects. Current and future global LNG demand seems very gloomy.

According to the recent KPMG report for global LNG markets “Uncharted waters: LNG demand in a transforming industry,” global LNG demand will face many uncertainties in the future. The same report mentions that the factors which will affect the future global LNG demand are:

ÈÈ ÈÈ

Japanese nuclear restarts Ukraine crisis LNG storage Trading house vertical integration

In the medium term: ÈÈ ÈÈ ÈÈ ÈÈ ÈÈ

New buyer alliances ( JERA) Japanese deregulation Chinese economic growth New Russian pipelines New importers

LNG Gross Imports in Eastern Asia

Source: Cedigaz LNG Service Fig.1 - LNG Gross Imports in Eastern Asia, Source: Cedigaz, EASTERN ASIAN LNG GROSS IMPORTS DECLINED BY 3.9% IN 2015 TO 152.8 MT, 12/02/2016. http://blog.cedigaz.org/eastern-asian-lng/

Athanasios Pitatzis, M.Sc.

23

World LNG Estimated January 2013 Landed Prices

Source: Waterbone Energy, Inc. Data in $US/MMBtu. Updated: December 8, 2012 Fig. 2 - World LNG prices January 2013, Source: USA Federal Energy Regulatory Commission (FERC) https://www.ferc.gov/

World LNG Estimated January 2016 Landed Prices

Source: Waterbone Energy, Inc. Data in $US/MMBtu. Landed prices are based on a netback calculation. Note: Includes information and Data supplied by IHS Global Inc. and its affiliates ("IHS"); Copyright (publication year) all rights reserved. Prices are the monthly average of the weekly landed prices fot the given month. Updated: Feb-16 Fig. 3 - World LNG prices January 2016, Source: USA Federal Energy Regulatory Commission (FERC) https://www.ferc.gov/

SPRING / 2016





24

In the long term: ÈÈ ÈÈ ÈÈ ÈÈ

Asian urbanisation LNG in transport Renewable energy Climate policy

Exxon Mobil predicts in their report (published for the year 2016) “The Outlook for Energy: A View to 2040” that: ÈÈ

ÈÈ

ÈÈ

Global demand for natural gas will increase by 50 per cent from 2014 to 2040 Natural gas is projected to cover the 40 per cent of the future global energy demand until 2040 LNG exports expected to triple globally by 2040

Global LNG Market: Trends and Future Outlook

Differences in LNG prices from 2013 to 2016 per destination:

The price is the ratio of $US to MMBtu: ÈÈ

ÈÈ

ÈÈ

ÈÈ

Japan: From 15.38$ (January 2013) to 5.75$ (January 2016), a decline of 63%.

China: From 15.00$ (January 2013) to 5.60$ (January 2016), a decline of 63%.

UK: From 10.47$ (January 2013) to 4.65$ (January 2016), a decline of 56%.

Rio de Janeiro: From 12.10$ (January 2013) to 5.69$ (January 2016), a decline of 53%.

It is obvious from the above information and the LNG market trends that global LNG industry faces many uncertainties.

New emerging LNG markets

It is obvious that LNG industry has a bright long-term future ahead but the next 5 years are going to be challenging. According to the International Gas Union, major LNG importers for the year 2014 were Japan, South Korea, China, India, Taiwan and the UK . In the same year the major LNG exporters were Qatar, Malaysia, Australia and Nigeria. Until 2020 many LNG export facilities will have come online mainly in USA and Australia. East Asia LNG imports declined by 3.9 per cent in 2015 in comparison with 2014. The main factors for this decline, according to Cedigaz (an international association for natural gas), were unexpectedly low economic growth in that region, gas-fuel competitiveness and weather-related factors.

Moreover, LNG market is transforming to a globally united commodity market with increasing liquidity and competitive market all over the world.

These markets conditions will continue until 2020 or 2022. The decline in LNG prices is more than 50 per cent in some cases in a period of only three years from 2013 to 2016 (Fig. 2).

According to Energy Insights article “New LNG markets to carry future growth in demand,” the future emerging LNG importers will be: ÈÈ ÈÈ ÈÈ ÈÈ ÈÈ ÈÈ ÈÈ ÈÈ ÈÈ ÈÈ

Vietnam Uruguay South Africa Bangladesh Bahrain El Salvador The Philippines Ghana Cuba Morocco

According to the above picture, the recent LNG market entrants are Indonesia, Singapore, Pakistan, Egypt (after the discovery of Zohr, Egypt will be a gas importer only for the upcoming 2-3 years), Jordan, UAE , Kuwait, Puerto Rico, Dominican Republic, Argentina (thanks to high shale gas reserves, the country gas domestic production

Athanasios Pitatzis, M.Sc.

25

Fig. 4 - LNG Demand by country for recent and likely market entrants, Source: New LNG markets key to growth | Energy Insights. Retrieved: March 23, 2016, By James Walke, from https://www.mckinseyenergyinsights.com/insights/ new-lng-markets-key-to-growth.aspx

SPRING / 2016





Global LNG Market: Trends and Future Outlook

26

Total global LNG regasification capacity billion cubic feet per day

will recover in the near future), Mexico, Chile, Thailand, Malaysia and Poland. Most of the recent entrants are utilizing floating LNG storage and regasification unit (FSRU). The option of importing natural gas for countries that need it is quicker and cheaper than a land-based LNG import terminal.

FSRU Market

The FSRU market is rising and it is a new trend in global LNG market. The first FSRU was deployed in North America, more specifically in the U.S. Gulf of Mexico in 2005. Also, FSRU is a cost-effective solution for smaller or seasonal markets.

FSRU ’s are distributed around the world from South America, to Europe and Middle East. Finally, the future outlook for these vessels is promising thanks to emerging LNG importers, like India and the Philippines that will use this option to import LNG in the near future (2016 – 2017).

Future global LNG demand until 2020

According to the IEA chart, the future LNG demands until 2020 will be generated mainly by Europe, China, India and Middle East.

Conclusion

Fig. 5 - Total global LNG regasification capacity, Source: Floating LNG regasification is used to meet rising natural gas demand in smaller markets - Today in Energy - U.S. Energy Information Administration (EIA). (n.d.). Retrieved: March 23, 2016, from http://www.eia.gov/todayinenergy/detail. cfm?id=20972

The LNG glut, according to many LNG experts like Cedigaz and IEA , is most likely to last until 2022.

According to the Gas Strategies, in 2016 eight LNG import terminals with a total capacity of 42.3 mtpa are going to be set up. Most of these terminals are located in China (5), one in France, one in Ghana and one in Colombia. At the same time, according to the Gas Strategies, 15 LNG exports projects are targeting to get FID (Final investment decisions) in 2016. Most of these projects are located in the US, Canada and Mozambique. Changing market dynamics, political decisions over the environmental rules, global economic growth, China’s future energy mix, Europe’s domestic gas production, USA’s shale gas industry future outlook and geopolitical implications are the main factors which will determine the future global LNG outlook. 

Athanasios Pitatzis, M.Sc.

27

Fig.6 - Growth of gas imports by region, Source: International Energy Agency (IEA)

References 1. KPMG GLOBAL ENERGY INSTITUTE, Uncharted waters: LNG demand in a transforming industry Report, http://www.kpmg.com/ID/en/IssuesAndInsights/ArticlesPublications/Documents/uncharted-waters-LNG-demand-transforming-industry.pdf 2. New LNG markets key to growth | Energy Insights. Retrieved March 23, 2016, By James Walke, from https://www.mckinseyenergyinsights.com/insights/new-lng-markets-key-to-growth.aspx 3. The outlook for LNG in 2016– supply growth but where is the demand?, Gas Strategies, http://www. gasstrategies.com/sites/default/files/download/outlook_for_2016_-_gas_strategies.pdf

SPRING / 2016



SPRING / 2016



Strategies in addressing obsolescence on the subsea control systems

30



Strategies in addressing obsolescence on the subsea control systems for deep offshore field developments Riverson Oppong, M.Sc.

**Gubkin Russian State University of Oil and Gas ÞÞRussia riverstec@yahoo.com DDRobin Winkle, Development Manager – Lukoil Overseas Offshore Projects Ltd.  University  Country  E-mail  Supervision The increasing world energy demands for enhanced oil and gas recovery in the offshore industry has led to new subsea technology developments with augmented system functionality. Technologies such as subsea processing and instrumentations for subsea control data acquisition place a countless demand on bandwidth, power and capacity. Thus, the legacy control system turns out to be obsolete and proves unsustainable in supporting the increased functionality placed on it by the new subsea technologies. With the reckless advancement of electronics, the replacement of the basic components of the control system when they fail becomes problematic as they are no longer being manufactured or supported by the original component manufacturers (OCM).

Obsolescence An equipment or module turn out to be obsolete (out-of-date) once it is no longer manufactured by the original equipment manufacturer

(OEM) or a state where the technical support for the product has been introverted and again when the innovative life cycles of components are much shorter than the seemingly system life cycle. Obsolescence on the other hand refers to the period after which the original manufacturer of equipment ceases further manufacturing of equipment or providing technical support for the given product; leading to the depletion of the remaining components or equipment [3,4]. This is also known as Diminishing Manufacturing Sources and Material Shortages (DMSMS) [6,8].

This implies that like-for-like replacement for the product becomes impossible [1] Obsolescence in Subsea Production Systems (SPS)

Some of the systems which are most likely to experience obsolescence in Subsea Production System are mainly the Subsea Production Control System (SPCS) and some complex subsea system such as the High Integrity Pressure Protection System, Subsea Processing Units (SPU) and even down-hole equipment (Electrical Submersible Pump, etc.). Some of these systems are more susceptible to obsolescence than the others and therefore need more attention.

Among the major items in a subsea production system, it is observed in Table 1, that the major area of concern for obsolescence management lies in the subsea control module.

Riverson Oppong, M.Sc.

31

Unit/equipment

Core component

Technology evolution

Replacement alternatives

Obsolescence (risk)

HPU

Electrical

Moderate

Less difficult

Low

EPU

Electrical

Moderate

Less difficult

Low

Umbillical and umbillical termination assembly

Mechanical

Low

Less difficult

Low

Electrical/hydraulic flying lead

Mechanical

Low

Less difficult

Low

Subsea booster pump

Mechanical

Moderate

Difficult

Moderate

Subsea separator

Mechanical

Moderate

Difficult

Moderate

Software

Programme

High

Less difficult

Moderate

Subsea control module

Electronics

High

Very difficult

Very high

Obsolescence management

Tab.1 - Obsolescence Criticality in Subsea Production System

Obsolescence Resolution Approach

Obsolescence management involves all the activities, strategies and resolutions applied in addressing obsolescence issues. It applies risk management to reliability, rate of failure of component and obsolescence as related entities. Obsolescence management is concerned with reliability because obsolescence does not count except the equipment fails (i.e. unreliability). Hence, this calls for the need to adopt a realistic strategy to manage obsolescence. [8].

When a part becomes obsolete, a resolution approach must be applied instantly to attack the problem. It is important to make sure that no pre-existing abilities are lost with the resolution approach selected. There are several resolution approaches in the literature which are described as follows, but the suitability of them depends on the individual case. The different approaches are classified in line with the replacement used into four categories.

In the late 2000s, Herald et al. demonstrated that by improving the obsolescence management, the costs related can be significantly reduced. Figure 1 shows how the evolution of the obsolescence level differs from implementing a proactive versus a reactive approach.

Field case study and methodology

Obsolescence Mitigation Measures

The approach followed in the obsolescence management is typically a combination of mitigation measures. Obsolescence risk can be mitigated by taking actions in three main areas: supply chain, design and planning as shown in Figure 2.

The field “X” is situated in the Norwegian North Sea at water depth of 200 to 300m. It came on stream in 1994 with further developments within 8 years.

Due to the need for IOR , the first SSBI system was implemented. Apart from the SSBI unit, several new technological developments enhancing field surveillance and reservoir monitoring were

SPRING / 2016



ďƒƒ

32

Strategies in addressing obsolescence on the subsea control systems

Fig. 1 - Advancement of the Level of Obsolescence Based on the Management Method (Herald et al, 2007)

Fig. 2 - Obsolescence Mitigation Approaches

Fig. 3 - Obsolescence Resolution Strategy

Riverson Oppong, M.Sc.

needed to improve reliability, availability and throughput. Some of these components or equipment included sensors, capacitance hydrocarbon leak detectors, acoustics and detector, and acoustic hydrocarbon detector. The power demand and high bandwidth exceeded the capacity of the legacy control system leading to obsolescence if no action had been taken.

33

ÈÈ



Cost of loss oil production = production rate (BOPD)* duration (days) * oil price (2)

Within the period of the field life, it is assumed that the resolution was implemented in years 4, 8, 12 and 16.

(1×24.821)+(12.123×75× 25.5×7) (1×24.821 + 4 (1+0.18)

The increased functionality estimated in this (1×24.821)+(12.123×75× 25.5×7) (1×24.821)+(3,644×75×0.5×7) field thus necessitated a conforming technolo++ 4 8 (1+0.18) gical advancement in the control(1+0.18) system which is proficient to back the high power, high speed, (1×24.821)+( 2.752×75×0.5×7) (1×24.821 + + increased data-handling capacity and reliability 12 (1+0.18) demand placed by the new technology. These new technologies include the SPU, Intelligent (1×24.821)+( 2.752×75×0.5×7) (1×24.821)+(978×75×0.5×7 ) ++ 12 16 Well Interface Standardization, Subsea Instru(1+0.18) (1+0.18) ment Interface Standardization and other sensor = US$97,077,241 (3) constituents for effective supervisory control and monitoring system.

Where: 1

Cost analysis

ÈÈ

ÈÈ

The analysis is centered on the following figures and assumptions: ÈÈ ÈÈ

ÈÈ

ÈÈ

ÈÈ

ÈÈ

IOR of the entire field is 35 Million Barrels Duration of field is assessed to be of about 17 years CAPEX for the field’s advancement is US$298 Million.

Oil price will remain steady at US$75 per barrel throughout the field life; Discounted rate for the period is 18% and there is no redundancy in the system;

ÈÈ

ÈÈ

(1+0.18) represents discount factor for the respective years with 18% discount rate.

US$24,812 is the substitute resolution cost for each occurrence.

13,123BOPD, 3,644 BOPD, 2,752 BOPD, 978BOPD represents estimated production profile of the field at years 4, 8, 12 and 16, respectively. (US$95 is the average price per barrel.)

25.5 weeks represents the total time in weeks for “substitute” resolution and time spent for installation. This takes place only for the first substitute resolution implementation.

0.5 weeks represent time for installation and 7 represents number of days in a week

Cost Impingement on Reactive Strategy

To calculate cost of each resolution for the reactive obsolescence field, the following equations are applied ÈÈ

Reactive obsolescence cost = cost of loss oil production + field life cost of the given resolution (1)

The procedure is applied for the different resolutions and the result is as shown in Table 2.

The total cost using a reactive approach is computed as roughly equal to US$478 million. Figure 5 represents the comparison of the different resolution as adapted for the field reactive resolution strategy.

SPRING / 2016

ďƒƒ

Strategies in addressing obsolescence on the subsea control systems

34

Resolution

Cost (Million US$)

Resolution

Cost (Million US$)

Existing stock

1.036190476

Existing stock

1.036190476

Reclamation

0

Reclamation

0

Alternate Source

53.18171513

Alternate Source

16.22171513

Substitute

97.007241

Substitute

1.77084869

LOT buy

36.80480647

LOT buy

3.204806475

Alternate Manufacture

71.88328777

Alternate Manufacture

1.323287771

Emulation

88.13333329

Emulation

0.773333292

Redesign minor

141.2905711

Redesign minor

0.170571141

Redesign major

0

Redesign major

0

Total

478.100753

Sum for proactive management

1.7

Total

26.20075298

Tab. 2 - Individual Resolution Cost for Reactive Approach (Source: Abili N, Citi G, Eni E&P; Onwuzuluigbo R, Saipem, 2013)

Tab. 3 - Individual Resolution Cost for Proactive Approach (Source: Abili N, Citi G, Eni E&P; Onwuzuluigbo R, Saipem, 2013)

Fig. 5 - Reactive Strategy Field Life Resolution Cost Impact (Source: Abili N, Citi G, Eni E&P; Onwuzuluigbo R, Saipem, 2013)

Riverson Oppong, M.Sc.

35

Fig. 6 - Proactive Approach Field Life Resolution Cost Impact (Source: Abili N, Citi G, Eni E&P; Onwuzuluigbo R, Saipem, 2013)

Fig. 7 - Comparing Proactive and Reactive Strategy Obsolescence Management Cost in Field Case Study (Source: Abili N, Citi G, Eni E&P; Onwuzuluigbo R, Saipem, 2013)

SPRING / 2016





36

Strategies in addressing obsolescence on the subsea control systems

Cost Impingement on Proactive Stratagem

OPEX calculation ÈÈ

A similar approach just for calculating cost impact using the reactive strategy was used to estimate that of proative method. The cost of loss in production using the reactive approach is lessened radically to 6% as resolutions are proactively implemented before the failures arise. Whereas in the instance of reactive approach no budgetary cost is set aside, proactive approach sets aside a annual contract amount of $100,000 which is equivalent to $1.7 Million for the 17 year period to improve the efficiency of proactive approach.

Total OPEX = total fixed cost + total variable cost + total obsolescence cost + decommissioning cost (5)

Therefore assuming a fixed cost of US$8 million per year, a variable cost of US$10 per barrel and a decommissioning cost of US$5 million, Total OPEX of field for a reactive strategy in obsolescence management is calculated as; ÈÈ

($8 million per year * 17 years) + ($10 per barrel * 35 million barrel) + $478 million = US$964 million (6)

The overall cost using a proactive method on the field is calculated as approximately equal to $26.2 Million.

Where, $26.2million is the proactive resolution cost of the field for the 17 years period.

Figure 6 represents the comparison of the different resolution as adapted for the field case study.

In addition, the total OPEX of field for proactive strategy is calculated as:

Matching Proactive and Reactive Resolution Strategy

ÈÈ

Comparing the resolution cost metrics for the two strategies is represented in Figure 7. It signifies that the major resolution cost lies in the redesign.

Hence right management is necessary to mitigate it by being proactive.

Obsolescence Management Cost and Field OPEX Calculation of Rate of Income Returns (ROR)

The revenue for the field was calculated according the equation given below. ÈÈ

ROR = recoverable reserve * price of oil (4)

Where recoverable reserve = 35 million barrels, and price of oil per barrel = $95. Hence the revenue for 17 years of extended field life will cost US$3.325 billion.

($8 million per year * 17 years) + ($10 per barrel * 35 million barrel) + $26.2million = US$512.2 million (7)

Where, $26.2million is the proactive resolution cost of the field for the 17 years period.

Total Expenditure

To calculate the total expenditure: ÈÈ

Total expenditure = total CAPEX + total OPEX + Decommissioning

Where the total CAPEX from the field SSBI award is US$298 million and decommissioning cost is $5 million. Therefore, total expenditure for the reactive and proactive approach stands at US$1.222 billion and US$815.2 million, respectively. (Note: calculation is made based from the time of investment of SSBI to end of field life)

Riverson Oppong, M.Sc.

Profit

The profit is derived based on the following equation: ÈÈ

Profit = revenue – total expenditure

Therefore profit before tax for the system that uses reactive approach is: ÈÈ

$2.8 billion – $1.267 billion = US$1.533 billion (9)

The profit before tax for the system that uses a proactive approach is: ÈÈ

$2.8 billion – $815 million = US$1.985 billion (10)

Discussions, analysis and conclusion Considering the two obsolescence management approaches studied in this paper, it can be seen that reactive approach stands at $478 million while that of the proactive approach stands at $26.2 million.

37

The proactive cost in this case study is approximately 18 times less than the reactive cost. These costs have direct influence on the profit before tax of the field which stands at $1.533 billion and $1.985 billion for the reactive and proactive approach correspondingly. The profit difference in the two scenarios is approximately twice the CAPEX investment of SSBI. The outcome shows that reactive approach is not suitable to subsea facility particularly for extended years of field development. However, the only exceptions can be in situations where (1) the field life is very short. (2) There are no opportunities for additional development. (3) There are dependable OCM guarantees.

The present paper appraised the approaches established in other industrial sectors to address obsolescence in the Deep Offshore oil and gas industry with an attention on the most vulnerable systems component. A case study was carried out on a typical brown field development which demonstrated that while a reactive approach to obsolescence management in subsea facility can be very risky and costly; a proactive approach can be more applicable and less expensive with respect to the operational cost. 

References 1. Abili N, Citi G, Eni E&P; Onwuzuluigbo R, Saipem, Managing the Impact of Obsolescence on Subsea Field Development in the Deep Offshore Industry, 2013_ http://pennwell.websds.net/2013/dot/papers/ t1s1o4-paper) 2. Aker Solution (2009), Managing obsolescence and new technology requirement, available at: http:// www.sut.org.au/perth/perth_events/Aker_Solutions_Low_power_SEM_managing_obsoles cence_060809.pdf (accessed May 12, 2012).

3. Baker, J, (2011), Guidelines for the management of obsolescence in subsea facilities, Energy Institute, London.

4. Cretenet, A. (2004), Obsolescence of electronics potential impact on subsea control from an operator’s standpoint, in Subsea Control and Data Acquisition: experience and challenges,

SPRING / 2016



ďƒƒ

38

Strategies in addressing obsolescence on the subsea control systems

5. Mackenzie, R., (2011), Controlling tomorrows subsea technology: providing increased system functionality and embracing obsolescence management, Deep Offshore Technology Conference, 11-13 October 2011, New Orleans USA 6. McDermott, J., Shearer, J. and Tomczykowski, W. (1999), Resolution cost factors for diminishing manufacturing sources and material shortages, final report, contract no.GS-35F-4825G, ARINC, Annapolis, Maryland.

7. Ministry of Defence (2010), the defence logistics support chain manual: obsolescence management, JSP 886, Vol. 7, part 8.13, Ministry of Defence, United Kingdom.

8. Sandborn, P. (2007a), Software obsolescence- complicating the part and technology obsolescence management problem, IEEE Trans. on components and packing technologies, vol. 30, No.4, pp. 886-888.

9. Tester R. (2010), Solutions for improved operational efficiencies and enhanced oil recovery by mid-life technology insertion into older fields. Paper No. SUT SCADA 10-107, London; Society of Underwater Technology.

Ruban Paramasivam



39

Nanomaterial additive in oil based mud for high temperature condition Ruban Paramasivam

**Universiti Teknologi Malaysia ÞÞMalaysia mst.seefi@yahoo.com DDAbdul Razak Ismail, Assoc. Prof  University  Country  E-mail  Association

Drilling fluid, also known as drilling mud, plays a crucial role in drilling operation. However, it is often impossible for conventional drilling fluids to fulfil certain functional tasks that are deciding in a challenging operation. The limited thermal stability of used additives can alter mud properties drastically when facing high temperature condition. Thermal degradation of additives leads to a loss in rheological properties of the mud, which can cause serious operational problems derived from the severe filtrate loss and thick mud cake formation. Therefore, the application of nanomaterial as an additive may resolve the task generated by deepwater operation. Nanomaterial has a huge surface area to volume ratio, which gives it a potential to form a desirable thin mud cake with only few requirements. An experiment was conducted to identify the rheological behaviour, mainly filtrate-loss volume and mudcake thickness of oil-based mud with nanomaterial (nanoclay cloisite) as fluid loss additive. Four different standard room condition temperatures were tested on the muds of 91°F, 250°F, as well as 350°F and 450°F at atmospheric pressure. Thanks to the experiment it could be proven that if adding nanomaterial additives to oil-base mud, it becomes more thermally stable, which can be observed in the increment of yield point, plastic viscosity, gel strength, thin mudcake and low filtration volume, even after exposing it to high temperature condition.

Study background

During drilling operation drilling fluid also known as mud, needs to be continuously circulated along drill pipe and through the drill bit before it flows back to the surface via annulus.

One of the very crucial significance of drilling fluid is to provide sufficient hydrostatic pressure to the wellbore and prevent the formation fluids from entering into it. Mud also walls the borehole with impermeable mudcake in order to prevent it from being contaminated by drilling fluid. There are many other significant purposes of drilling mud, among which are: improving hole stability, minimising sloughing and caving, helping to obtain good downhole data, as well as allowing efficient cutting lifting. All these purposes are possible to be achieved by drilling mud with addition of particular mud additives that will enhance the properties according to the demand of certain downhole condition and technical requirement. It is very important that a drilling mud be suitable for a satisfactory use in harsh conditions, especially for deepwater drilling challenges. Additives used in drilling mud, specifically in high temperature condition, should not degrade, so that the rheological stability with operational time and temperature is sustained. One of the crucial additives applied in drilling mud is the fluid loss additive (FLA). FLA is required to reduce fluid loss in order to prevent formation damage. This nanomaterial has a high potential to be tailored as mud additive

SPRING / 2016





40

Nanomaterial additive in oil based mud for high temperature condition

by the developed current nanotechnology. The application of nanotechnology in drilling fluid can revolutionise the additive characteristics. Nanomaterial played a significant contributing role as an additive because of its high surface area to volume ratio, which requires only a small amount of such an additive. What is more, nanomaterial has also a high thermal stability that it is suitable to be applied in high temperature condition.

be used here, however, using them in such conditions showed to be limitated [24]. The limited thermal stability of conventional macro and micro material-based chemicals and polymers in HTHP conditions can alter mud properties dramatically and lead to different borehole problems. Thermal degradation of bentonite mud, conventional starch-based fluid loss additives, viscosifiers, etc., due to the thermal stress effect, is well known to the industry [4].

Objectives

The followings are the objectives of the research: 1. to study the effects of high temperature exposure towards standard oil-based mud (OBM) with and without the application of nanomaterial additive, 2. to study the effects that different amounts of nanomaterial additive have onmud’s rheological properties.

High Temperature High Pressure Conditions (HT/HP)

High pressure and high temperature (HP/HT) conditions are strictly defined as pressures greater than 10,000 psi and temperature above 300°F. Even though there is nothing extraordinary about these numbers, they cover a transition to increasingly hostile environments. Several completions have been installed in higher pressures and temperatures, named ultra HP/HT, which are above 25,000 psi and 450°F [7].

Drilling fluid challenges in HT/HP

HP/HT wells, by definition, require a higher density fluid, which typically requires high solid loading. The resulting higher pressures, combined with rock competence at depth, lead to low penetration rates, extending time on location and added drilling costs [8]. Selecting proper additives for an extreme environment becomes critical for appropriate rheological properties and fluid loss control. A multitude of synthetic polymers could

Application of Nanomaterial in Drilling Fluid

Nanomaterial has great a potential for a broad use in the drilling industry. Nanotechnology is not new, but its application in the oil industry is certainly in its infancy, including drilling applications. Adding nanomaterial to the drilling mud can modify its properties and their suspension has many advantages. They can impart sedimentary, thermal, optical, mechanical, electrical, rheological and magnetic properties to a base fluid that can improve its performance [23]. Oil exploration has been using nanotechnology in drilling muds for the past 50 years. The nanoparticles in drilling muds are made of clays and they contain naturally occurring 1 nm thick discs of aluminosilicates.

The nanoparticles reveal to have extraordinary rheological properties in water and oil [19]. Recent studies indicate that successful applications of nanotechnology in drilling are likely to occur with synthetic nanoparticles, where size, shape and chemical interactions are carefully controlled to achieve the desired fluid properties and drilling performance [23]. Drilling, drill-in or completion fluids that contain at least one additive with particle size in the range of 1 to 100 nanometres are defined as nano-based drilling, drill-in and completion fluids [3]. Physically, a nanosized particle has a dimension that is one billionth of a metre. Usually, a typical human hair has a diameter of about 80,000 nanometres, which equals roughly the width of 10 hydrogen atoms if measured using an atomic scale (Mokhatab et al., 2006). Compared to the macro and

Ruban Paramasivam

41

Fig. 1 - Mud weight versus amount of cloisite by percentage of mud weight

Fig. 2 - Plastic viscosity versus Amount of cloisite by Percentage of Mud Weight

micro-sized materials, nano-sized materials have a drastically higher surface area to volume ratio.

Figure 2.1 shows the surface area to volume ratio of a unit volume/mass of macro- (1 mm), micro- (1 micron) and nano-sized (1 nanometre) spherical particles. The data show more than a million-fold increase in the surface area to volume ratio if a macro particle is converted into nano-sized particles. By virtue of the huge surface area of the nano-material and the predominant role of surface, Van der Waals, molecular and atomic forces over the physical forces, nanoparticles are expected to produce exceptional fluid properties

with a tiny concentration of the nano-material (<1%) in the fluid system [3]. The ability to create tailored-made particles with custom-made behaviour is also going to play an important role in superior nano-based fluid formulation. Thus, the application of nano-based fluid additives in formulating high performance water and oil-based mud systems has the potential to overcome the current as well as future technical challenges faced by the oil and gas industry. The extremely high surface area to volume ratio of nanomaterials compared to the macro and micro materials of the same mother source provides them with

SPRINGâ&#x20AC;&#x2030;/â&#x20AC;&#x2030;2016

ď&#x192;&#x192;

ď&#x192;&#x192;

42

Nanomaterial additive in oil based mud for high temperature condition

dramatically increased interaction potentials with reactive shale to eliminate shale-drilling mud interactions and the associated borehole problems [3]. The potential of nanomaterials to form a well-dispersed plastering effect on the borehole wall with concentration of less than 1% in a drilling mud system is expected to improve the fluid and drilling performance significantly.

When the size of nanomaterials approximates in less than the wavelength of conduction electrons, the periodic boundary damage, and magnetism, internal pressure, optical absorption, thermal resistance, chemical activity, catalysis and melting point undergo great changes that are unlike of normal particles [13]. The surface effect is the change of the nano6rwmaterialâ&#x20AC;&#x2122;s properties that occurs when the number of surface atoms increases while the size of the particles decreases.

The surface/volume ratio of nanoparticles is 1000 times larger than that of micro particles. Atoms at the surface of the nanoparticles, without atoms surrounding them, are in a different environment than inner atoms. Because of the unsaturated dangling bonds, they tend to be coalescent with others in order to become stabilised, so their specific area, surface energy and surface coalescence energy increase rapidly, manifesting in high chemical activity and strong ability of absorption [13].

Nanomaterials have unique properties due to their small size and high surface area per unit volume. As a result, they are found useful in many applications, including oil and gas exploration and production. Nanomaterials appear to be stronger and more reactive than non-nanomaterials. The transition from micro to nanoparticles leads to changes in physical as well as chemical properties of a material. Two of the major factors are the increase in the ratio of the surface area to volume, and the size of the particle. The increase in surface area-to-volume ratio, which increases as the particles get smaller, leads to an increasing dominance of the behaviour of atoms on the surface area of particles over those in the interior of the

particle: this affects the properties of the particles when they interact with other particles. Because of the higher surface area of the nanoparticles, the interaction with other particles within the mixture is greater, potentially leading to increased strength of the material, heat resistance and other properties of the mixture.

Properties of nanomaterials depend highly on the shape, orientation and structure of individual nanoparticles [23]. The extremely greater surface area to volume ratio of nanoparticles can offer several technical benefits for safe and economic drilling operation. The huge surface area to volume ratio of nano-based mud additive is expected to improve the thermal conductivity of these fluids. Hence, the enhanced thermal conductivity of drilling mud will provide efficient cooling of drill bit and a significant increase of its operating life cycle. Besides that, the design of a nano-based drilling fluid using tailored-made nanoparticles of extremely high thermal stability and heat transfer coefficient can save millions of dollars associated with equipment damage, repair, failure or replacement. Due to the presence of a massively high number of extremely tiny particles with huge surface area, high heat tolerance, high thermal conductivity, high mobility, effective interaction with external and internal rock surfaces, nano-based drilling mud systems are expected to play a pivotal role in current and future HT/HP drilling operations, complex drilling conditions and deep water drilling operations [3].

Recent research which related to application of nanomaterial in drilling fluid is using nanoparticles to decrease differential pipe sticking and its feasibility in Iranian oil fields. These nanoparticles are carbon black particles, which added to drilling mud, perform some fuctions. This advantage of carbon black, which has nanometre-size particles, causes to make a mud cake, which is more continuous and integrated (it means that mud cake has low permeability). So, by having integrated and low permeability mud cake, it has less volume of filtrate and therefore mud cake thickness is less

Ruban Paramasivam

43

Material

Function

Volume/Mass

Sarapar 147

Base oil

375 ml

Confimul P

Primary emulsifier

4.8 ml

Confimul S

Secondary emulsifier

6.3 ml

Distilled Water

Produce brine

41.7 ml

Calcium Chloride

Produce brine

15.2 g

Configel

Gel forming additive

7.5 ml

Confitrol

Fluid loss additive

10.5 ml

Calcium Carbonate

Alkaline medium

6.0 g

Barite

Weighting agent

300 g

Tab. 1 - Standard OBM Formulation

than in usual cases [1]. Besides that, there are scientists at China’s Shandong University who are researching ways in which nanotechnology can be used to improve drilling process. In their specialised petroleum laboratory, they have developed an advanced fluid mixed with nano-sized particles and superfine powder that significantly improve drilling speed [14].

Test procedure, standard OBM formulation

Standardised oil-based mud was prepared for all the tests in this study. The base components used in the formulation are listed in Table 1. The base mud was prepared and formulated base on 500 ml scale using Hamilton-Beach Commercial Mixer. Sarapar oil was placed inside the mixer and Confimul P was added into the sarapar using a syringe and being let stirred for 2 minutes, followed by addition of Confimul S and being let stirred for 5 minutes. Brine water was added into the mixer and stirred for 10 minutes. Configel and Confitrol were added into the system sequentially at intervals of five minutes. Finally, barite was added to the system and stirred for approximately ten minutes to obtain a homogeneous system. The prepared mud was classified as class A and further subjected for the laboratory mud test procedures.

The standardise OBM was further subjected to the addition of a nanomaterial, namely cloisite, in five different amounts, as shown Table 2.

Mud test laboratory procedure

All the methods used were conducted according to standard American Petroleum Institute (API) specification, namely “Recommended Practice on Standards Field Procedure for Testing Drilling Fluid” API RP 13B as well as the API 131. The mud was tested to determine the most stable rheological properties. The results from the experiment were recorded and compared to see the effect of additives added. The rheological properties test consisted of: 3.

4.

5.

6.

7.

mud density plastic viscosity yield point gel strength mud filtration and mud cake thickness

Results and discussion

Table 3 shows the rheological properties of standard OBM used in standard room temperature (91°F), 250°F, and high temperature condition of 350°F and 450°F. It can be seen that the basic

SPRING / 2016





Nanomaterial additive in oil based mud for high temperature condition

44

Nanomaterial content (by Weight of base mud) 0.00 % 0.05 % 0.10 % 0.20 % 0.30 % 0.50 %

Tab. 2 - Nanomaterial content applied in each mud

Parameter

Room Temp.

(91°F)

Ageing at Room Temp.

(91°F)

Ageing at 250°F

Ageing at 350°F

Ageing at 450°F

Mud Weight (ppg)

9.8

9.8

9.8

9.5

9.4

600 RPM (cp)

29

32

37

41

46

300 RPM (cp)

19

20

24

27

30

PV (cp)

10

12

13

14

16

AV

14.5

16

18.5

21

23

YP (Ib/100ft2)

9

8

11

13

14

Gel Strength (10 sec)

3

3

3

5

6

Gel Strength (10 min)

4

4

8

7

3

Fluid Loss (ml/30 min)

8.2

8.6

8.9

12.2

15.2

Mud cake (/32 in)

2.4736

2.496

2.6336

3.4496

6.0928

pH

9

9

9

9

9

Tab. 3 - Basic (standardized) mud properties Effect of nanomaterial additive on mud weight

mud rheological property does not significantly change when tested within 250°F. However, this result revealed that there is a change in rheological properties when standard OBM is being exposed to high temperature condition. High temperature condition degrades the original texture of the mud whereby it changes the physiochemical of the OBM . Table 4, Table 5, and Table 6 show the rheological data obtained when nanomaterial was added the OBM .

It is crucial to design mud weight according to the hydrostatic pressure of wellbore. Nanomaterial (cloisite) addition to OBM does not show any significant effect on mud weight. Nanomaterial addition in this experiment was within 0.5% of the weight of OBM , which would not affect on mud weight since this value is majorly controlled by amount of weighting agent (barite). Within 250°F, the mud weight was still in original value; however, when tested after an exposure to high

Ruban Paramasivam

45

Parameter

BHR (91°F)



Ageing BHR (91°F)

Nano additive (% by weight of mud)

0%

0.05%

0.10%

0.20%

0.30%

0.50%

0%

0.05%

0.10%

0.20%

0.30%

0.50%

Mud Weight (ppg)

9.8

9.8

9.8

9.8

9.8

9.8

9.8

9.8

9.8

9.8

9.8

9.8

600 RPM (cp)

29

29

36

36

39

40

32

32

36

38

40

42

300 RPM (cp)

19

19

25

25

27

28

20

20

23

24

26

28

PV (cp)

10

10

11

11

12

12

12

12

13

14

14

14

AV

14.5

14.5

18

18

19.5

20

16

16

18

19

20

21

2

YP (Ib/100ft )

9

9

14

14

15

16

8

8

10

10

12

14

Gel Strength (10 sec)

3

3

3

3

3

3

3

3

3

3

3

3

Gel Strength (10 min)

4

4

5

5

5

5

4

4

5

5

6

6

Fluid Loss ml/30 min)

8.2

8

7

6.5

6.5

6.5

8.6

8

8

7.3

7.2

7.2

2.08

2.08

2.496

2.464

2.1357

2.128

9

9

9

9

9

9

Mud cake (/32in) pH

2.4736 2.4672 2.4064 2.1888 9

9

9

9

2.3488 2.2496 9

9

Tab. 4 - OBM properties with nanomaterial additive at standard room temperature

Parameter

AHR 250°F

Nano additive (% by weight of mud)

0%

0.05%

0.10%

0.20%

0.30%

0.50%

Mud Weight (ppg)

9.8

9.8

9.8

9.8

9.8

9.8

600 RPM (cp)

37

37

40

43

45

47

300 RPM (cp)

24

24

26

28

29

31

PV (cp)

13

13

14

15

16

16

18.5

18.5

20

21.5

22.5

23.5

YP (Ib/100ft )

11

11

12

13

13

15

Gel Strength (10 sec)

3

3

3

3

3

3

Gel Strength (10 min)

8

8

9

10

10

11

Fluid Loss ml/30 min)

8.9

8.5

8

7.9

7.6

7.6

Mud cake (/32in)

2.6336

2.5792

2.4

2.3328

2.064

2.0384

pH

9

9

9

9

9

9

AV 2

Tab. 5 - OBM properties with nanomaterial additive after 16 hours in 250°F holler oven

SPRING / 2016

Nanomaterial additive in oil based mud for high temperature condition

46



Parameter

AHR 350°F

AHR 450°F

Nano additive (% by weight of mud)

0%

0.05%

0.10%

0.20%

0.30%

0.50%

0%

0.05%

0.10%

0.20%

0.30%

0.50%

Mud Weight (ppg)

9.5

9.5

9.5

9.5

9.5

9.5

9.4

9.4

9.4

9.4

9.4

9.4

600 RPM (cp)

41

41

45

48

50

51

46

46

50

52

55

55

300 RPM (cp)

27

27

30

32

33

34

30

30

33

35

37

37

PV (cp)

14

14

15

16

17

17

16

16

17

17

18

18

AV

20.5

20.5

22.5

24

25

25.5

23

23

25

26

27.5

27.5

YP (Ib/100ft2)

13

13

15

16

16

17

14

14

16

18

19

19

Gel Strength (10 sec)

5

5

5

5

5

5

6

6

6

6

6

6

Gel Strength (10 min)

7

7

8

9

10

10

3

3

5

6

6

6

Fluid Loss (ml/30 min)

12.2

9.87

9.1

8.9

8.6

8.5

15.2

13.5

12.4

11.5

10.2

10.1

Mud cake (/32in)

3.4496

2.8896

2.5984

2.304

2.2432

2.2432

6.0928

3.5104

3.0496

2.8864

2.8064

2.768

pH

9

9

9

9

9

9

9

9

9

9

9

9

Tab. 6 - OBM properties with nanomaterial additive at high temperature condition

temperature condition, mud weight was recorded to be decreased. This is due to the fact that the mud expanded (volume increment) because of the temperature and become less dense or, in OBM case, lower in mud weight.

Effect of nanomaterial on plastic viscosity

Plastic viscosity of OBM generally increased with addition of the amount of cloisite added.

Cloisite is nanoclay, derived from montmorilonite as its parent material. The addition of this nano particle can improve the mud viscosity. This nano-sized particle improves viscosity due to its contribution to the addition of solid content in the mud. From Figure 2, BHR PV value started to increase from 10 cP to 11 cP with cloisite addition

of only 0.1% by weight of OBM. The value increased again to 12 cP when 0.3% was added. After ageing 16 hours in room temperature, standard OBM was recorded to have higher PV value compared to OBM without ageing. PV was recorded to have increased from 12 cP to 13 cP with addition of 0.1% of cloisite by weight of OBM and ten times again with addition of 0.2%. When exposed to temperature, AHR 250°F, PV value of standard OBM is relatively higher than BHR and ageing BHR value. Ageing with temperature in roller oven in 250°F makes the mud particle be more kinetically active and causes more shear within the system that significantly will increase PV value. A significant increment in PV occurred when 0.1%, 0.2%, and 0.3% of cloisite by weight of OBM were added to the standard OBM . The addition of only 0.1% will increase PV of AHR

Ruban Paramasivam

350°F from 14 cP to 15 cP and addition of more cloisite will increase the PV value up to 17 cP. While for AHR 450°F, PV increment occurred with rise from 14 cP up to 19 cP with only 0.5%.

This shows that regardless of the temperature that is being applied, addition of nanomaterial will increase the PV value. Referring to Figure 3, regardless of the amount of nanomaterial, plastic viscosity value of OBM will increase with the increase of temperature exposure. This is due to the fact that when temperature is applied to the mud, particle destruction into smaller particles results in an increase of overall solid particle. The increase in solid particle inside the mud increases the viscosity value.

Effect of nanomaterial on yield point

Yield point or yield stress is the measure of minimum force that can cause mud to gel once it is motionless and it determines the carrying or holding capacity of the mud. With reference to Figure 4, addition of cloisite to OBM will increase the yield point value. The increase in yield point can be explained by the existence of higher attractive force in the fluid that originates from cloisite’s huge surface area, which leads to greater chemical reactivity. In room condition, BHR (before hot roll), yield point was recorded as 9 lb/100ft2 and increased to 14 lb/100ft2 when 0.1% of cloisite by weight of OBM was added. This increment continues up to 16 Ib/100ft2. When tested after ageing for 16 hours (Ageing BHR), yield point was observed to be lower than the value represented by BHR measurement. This can be explained by particle settlement that happened within the OBM, causing the yield point value to be lower than before ageing. This settlement caused non-homogeneity to the system and finally reduced the holding capacity of the system itself.

After ageing BHR , yield point value increment from 8 lb/100ft2 to 10 lb/100ft2 with addition of 0.1% of cloisite by weight of OBM was recorded.

This value continues to rise up to 14 lb/100ft2.

After being exposed to temperature of 250°F, yield point value increased compared to BHR

47

value. Addition of a nanomaterial also positively increased the yield point value of OBM AHR . An increment from 11 lb/100ft2 to 12 lb/100ft2 occurred with only addition of 0,1% of cloisite, which will continue to increase, as shown in the Figure 4, for example, up to 15 lb/100ft2. Furthermore, when continued to test the yield point after exposure to high temperature condition, nanomaterial proven able to significantly increase the yield point value even with small amount added. Even for high temperature condition, nanomaterial still was able to increase the yield point value. Referring to Figure 5 that shows clearly the effect of temperature exposure towards yield point value, the yield point value will increase with temperature. This explained that larger minimum forces are required to cause the mud to gel once it is motionless and the mud had higher holding capacity after being exposed to high temperature condition.

Effect of nanomaterial on gel strength

Gel strength is the ability of mud to develop and retain a gel structure and is measured after 10 seconds and 10 minutes. For standard OBM formulation described in previous chapter, gel forming agent is used as one of the additives.

Gel forming agent used, named Configel, enables OBM to retain gel structure easier. On the other hand, cloisites are similar to clay in nature, but with the advantage of size, cloisite improves the ability to hold gel structure by promoting the linking between particles. This can be observed in Figure 6 that shows the significant effect of cloisite after having been added to the OBM system.

With reference to Table 4, Table 5, Table 6 gel strength data for 10 seconds was not significantly altered by addition of cloisite. However, in high temperature condition, gel strength value for 10 seconds increased from the value of normal temperature. Figure 6 showed the gel strength value for 10 minutes, which significantly changed with the addition of cloisite. At room condition, BHR , gel strength increased from 4 to 5 when only 0.10% of cloisite by weight of OBM applied.

Ageing BHR gel strength value also increased

SPRING / 2016



ď&#x192;&#x192;

48

Nanomaterial additive in oil based mud for high temperature condition

Fig. 3 - Plastic viscosity versus temperature exposure

Fig. 4 - Yield point versus amount of cloisite by percentage of mud weight

Fig. 5 - Yield point versus temperature exposure

Ruban Paramasivam

from 4 to 5 when 0.10% of cloisite applied. This value increased again from 5 to 6 when 0.30% of cloisite applied. AHR at 250°F, gel strength was recorded to be increased from 8 to 9 when only 0.10% of cloisite applied. This value increased up to 11 when 0.50% of cloisite applied. In high temperature condition, nanomaterial was observed to have positive effect on the value of gel strength, similarily to the normal temperature condition. The application of only 0.10% of cloisite can increase the gel strength value. However, gel strength value in AHR 450°F was recorded to be lower compared to the value in 350°F. This is due to the extreme temperature condition that disrupts the OBM system but addition of cloisite within this high temperature proven to be able to increase the gel strength value. Better view on effect of temperature towards gel strength can be observed in Figure 7 whereby regardless of the amount of nanomaterial addition in mud, temperature exposure of within 250°F increases the gel strength value while high temperature condition of 350°F and 450°F decreases the gel strength value.

49

Fig. 6 - Gel strength (10 minutes) versus amount of cloisite by percentage of mud weight

Effect of nanomaterial on filtration and mud thickness

It is very desirable to obtain small volume of filtration and thin impermeable mud cake in order to decrease contamination of the formation that is being drilled and to avoid drilling operational problem deriving from thick or uneven mud cake.

Filtration is the liquid that passes through the medium, leaving the cake on the medium. In this thesis, standard OBM were tested with different amounts of nanomaterial additive. namely cloisite, to prove whether they can alter filtration volume and mud cake thickness. It can be observed in Figure 8 that an addition of only a small amount of cloisite can decrease the volume of filtration, regardless of the high temperature exposure. The reduction of fluid loss by cloisite was due to its bridging effect. Nanomaterial is known to have a potential to form a thin, non-erodible and impermeable mud cake during drilling whereby it

Fig. 7 - Gel strength versus temperature exposure

Fig. 8 - Fluid losses versus volume amount of cloisite by percentage of mud weight

SPRING / 2016



ď&#x192;&#x192;

50

Nanomaterial additive in oil based mud for high temperature condition

Fig. 9 - Filtration volume versus temperature

Fig. 10 - Mud thickness versus volume amount of cloisite by percentage of mud weight

Fig. 11 - Mud thickness versus temperature exposure

Ruban Paramasivam

51

provides linking to solid particles that form mud cake. From the figure, filtration loss increased drastically when high temperature of 350°F and 450°F were applied. However, additions of nanomaterial within these temperatures show positive results within only 0.05% to 0.3% of cloisite by weight of OBM being added.

shows that mud thickness produced was thicker after the mud was exposed to temperature. Mud thickness relates to the filtration volume whereby the more filtration volume produced, the thicker the mud cake thickness obtained.

Figure 9 shows clearly how temperature exposure to OBM affects the filtration volume regardless of the amount of nanomaterial added. This can be explained by the solubility of particle in OBM system, particularly the fluid loss additive itself.

With reference to Figure 10, mud cake thickness proven to decrease with addition of more cloisite of 0.5% by weight of OBM . Mud cake thickness at normal temperature value shows almost similar value; however, with addition of cloisite, mud cake thickness decreased. In high temperature condition of AHR 350°F and AHR 450°F, mud cake thickness was recorded thicker than that of normal temperature condition. However, with addition of cloisite, the thickness began to decrease. The cloisite increased the particle amount in the OBM system and nanoparticle was able to reduce mud cake thickness by fitting itself among other particle, which further produced a thinner and impermeable thin mud cake. Figure 11 clearly

There are several conclusions to be made after the analysis of the results. Firstly, nanomaterial additive has a potential to be tailored as mud additive since it has high thermal stability and can withstand high temperature condition. What is more, only small amount of particle (within 0.5% of mud weight) was required for the properties of oil-based mud, which are viscosity, gel strength, and yield point, to improve. This improvement proves the potential of nanotechnologies application in drilling fluid. Recommendations for further research on nanomaterial additive in drilling mud would be, firstly, studying the effect of different classes of nanomaterial with regards to size and parent material to obtain preference in choosing nanomaterial additive from fiscal and efficiency point of view. Secondly adding high pressure condition as one of the parameters to support the high potential of nanomaterial additive to be applied in HT/HP condition. 

Conclusion

References 1. Abouzar, MP, and Al-Anazi, B.D. (2008). Using Nanoparticles to decrease Differential Pipe Sticking and Its Feasibility in Iranian Oil Fields. Oil and Gas Bussiness.

2. Agarwal, S. et al., (2009). Using Nanoparticles and Nanofluids to Taylor Trasport Properties of Drilling Fluids for HT/HP Operations. National Technical Conference and Exhibition.18 May. New Orleans,Louisiana,1.

3. Amanullah et al. (2011). Preliminary Test Results of Nano-based Drilling Fluids for Oil and Gas Field Application. SPE/IADC Drilling Conference and Exhibition. 1-3 March. Amsterdam,Netherlands,2.

4. Amanullah, and Al-Tahini, A. (2009). NanoTechnology-Its Significance in Smart Fluid Development for Oil and Gas Field Application. SPE Saudi Arabia Section Technical Symposium and Exhibition.9-11 May. Alkhobar,Saudi Arabia,8.

5. American Petroleum Institute (2012). Recommended Practice Standard Procedure for Field Testing OilBased Drilling Fluids API RP 13B-2. (5th Ed.). American Petroleum Institute 6. Barnes, H.A., et al. (1993). An Introduction to Rheology. (3rd ed.). Amsterdam,Netherland: Elsevier

SPRING / 2016



ď&#x192;&#x192;

52

Nanomaterial additive in oil based mud for high temperature condition

7. Bellarby, J. (2009). Well Completion Design. (1st ed.). Amsterdam, Netherland: Elsevier.

8. Bland, R., et al. (2006). HP/HT Drilling Fluids Challenges. IADC/SPE Asia Pacific Drilling Technology Conference and Exhibition.13-15 November. Bangkok,Thailand.1.

9. Carpenter, G. (2006). Nanotechnology The plastic of The 21st Century. Guy Carpenter & Company Inc. 10. Hyne, N.J. (1991). Dictionary of Petroleum Exploration, Drilling and Production. Tulsa: PennWell Books 11. Jerry M. N., Battele (2005), Composition, Environmental Fates, and Biological Effect of Water Based Drilling Muds and Cuttings Discharged. Battele 12. Kamena, K. (2005), Nanoclays: Multidimensional New Nano-Tools in The Polymer Development Toolbox.

Southern Clay Products.

13. Kang, et al. (2010). Application of Micro and Nano Technologies in the Oil and Gas Industry-An overview of the Recent Studies. Abu Dhabi Exhibition and Conference.1-4 November.Abu Dhabi,UAE. 14. Krishnamoorti, R. (2006), Extracting the Benefits of Nanotechnology for the Oil Industry. Journal of Petroleum Technology. 24-26 15. Luppens, J.A., and Vilson, S.E. (1992), Manual on drilling, sampling, and analysis of coal. Philadelphia, PA, ASTM Manual Series MNL 11, 61 p 16. MI Swaco (1998). Engineering Drilling Fluid Manual. Chapter 3. Section 1-3 17. Mansoori, G.A. (2002). Advance in Atomic and Molecular Nanotechnology. University of Illionis.

18. Misstear, B.D.R., Banks, D., Clark, L. (2006). Water Wells and Boreholes. USA: John Wiley & Sons.

19. Mokhatab, S., Fresky, M.A., and Rafiqul, M. (2006) Application of Nanotechnology in Oil and Gas E&P. Journal of Petroleum Technology. 49-52.

20. Osman, E.A., and Aggour, M.A. (2003). Determination of Drilling Mud Density Change with Pressure and Temperature Made Simple and Accurate by ANN. SPE Middle East Oil Show and Conference. 9-12 June 2003. Bahrain.

21. Rabia, H. (1985). Oilwell Drilling Engineering, Principles and Practice. London:Graham and Trotma.

22. Reis, J.C. (1996) Environmental Control in Petroleum Engineering. USA: Gulf Publications.

23. Subodh, S., and Ramadhan, A. (2010). Vital Role of Nanopolymers in Drilling and Stimulations Fluid Applications. SPE Annual Technical Conference and Exhibition. 19-22 September 2010. Florence, Italy.

24. Stamatakis, E., Young, S., Stefano, G.D., MI SWACO, (2012). Meeting the Ultra HT/HP Fluid Challenge.

SPE Oil and Gas India Conference and Exhibition. 28-30 March. Mumbai, India.1.

25. Wolfgang, F. P. (2000). Drilling Engineering, Curtin University of Technology, Chapter 7. 191 - 204.

26. Young, D.B. (2007) Drilling Fluid. BP Research: Houston, Texas, USA

Patrycja Lanc

 Methane

53

hydrates – the new energy source?

Patrycja Lanc The history of methane hydrates starts in the 1960s in the Mossoyakha gas field in western Siberia, where scientists discovered the first documented deposits of ‘solid natural gas.’ Naturally occurring gas hydrates are now seen as a potentially vast energy resource. They contain a great volume of methane. One litre of fully saturated methane clathrate solid might contain about 120 grams of methane (or around 169 litres of methane gas at 0°C and 1 atm), which makes it a promising future source of energy, especially for countries that depend on import of gas, coal and oil, like Japan, South Korea, or Taiwan.

**AGH University of Science and Technology ÞÞPoland patrycja.lanc7@gmail.com  University  Country  E-mail as guest molecule) surrounded by the crystal cage of water molecules (host molecule), forming structures similar to ice, often named ‘flammable ice.’ When that guest is a methane molecule, then you have methane hydrate. However, not only methane can be encapsulated: many other gases have molecular sixes suitable to form a hydrate, e.g.: carbon dioxide or hydrogen sulfide. Fig. 1

What are gas hydrates?

Conditions of prevalence

Gas hydrates, also known as clathrate hydrates, are not officially chemical compounds. They are physical structures bound by hydrogen bonds and van der Waals forces. Gas hydrates are crystalline solids which consist of a gas molecule (known

The prime and most obvious condition of the formation of gas hydrates is of course the presence of correspondingly large quantities of water and gas, in this particular case, methane. The

SPRING / 2016



ď&#x192;&#x192;

54

Methane hydrates â&#x20AC;&#x201C; the new energy source?

Fig. 1 - Molecular structure of gas hydrate [5]

Fig. 2 - Physical conditions of the formation of gas hydrates [6]

Patrycja Lanc

necessary methane is mostly generated in the process of anaerobic digestion or less common volcanic exhalations.

Another important issue is pressure and temperature conditions. The deposits of methane clathrates have been recognized worldwide. In the places where pressure and temperature conditions stabilize the hydrate structure. That necessary condition, known as gas hydrate stability zone (GHSZ), occurs for example in oceanfloor sediments at water depths greater than 300-500m, where the bottom temperature is around 2o°C. Fig. 2 An important role in this process is also play by the layer of sediments. Hydrates form cement in

55

the pore spaces of sediment, and they also seem to have the capacity to fill up the sediment pore space and reduce permeability, so that hydrate-cemented sediments act as seals for gas traps.

We can see that in seafloor sediments, where gas hydrates bind immense amounts of methane, they can be found within a layer of sediments as much as around 1000m thick directly beneath the seafloor. However, gas hydrates can also form layers and outcrops of pure hydrate bonded to the seafloor, whereas onshore they are trapped in continental rocks in beds of sandstone or siltstone at depths of less than 800 m. Sandstones have relativity large pore spaces from where methane can be easily extracted. Nevertheless, such formations are not very common worldwide.

Fig. 3 -Types of methane hydrate deposits [2]

SPRING / 2016



ď&#x192;&#x192;

56

Methane hydrates â&#x20AC;&#x201C; the new energy source?

Deposits

Methane clathrates can be found naturally on Earth on the seabed, in ocean sediments, in deep lake sediments as well as in the permafrost regions. Fig.3 The largest deposits of methane hydrates are present in oceanic sediments along continental margins, for example at Blake Plateau on the western Atlantic continental rise, where one of the richest known deposits is located. Such a situation happens due to settlement of huge amount of dead biomass, transported by river to the sea, on the seafloor. This affects the high productivity of methane in coastal area.

Moreover, we can find methane clathrates on the Norwegian continental shelf, in the northern headwall flank of the Storegga Slide, located on the deep oceanfloor. Another known seawater locations are: the Gulf of Mexico, Nankai Trough in Japan, and also the Caspian Sea, Sea of Okhotsk, Black Sea and Mediterranean Sea.

Not only may gas hydrates be hosted by seawater, but also they can be found in deep fresh water lakes like Lake Baikal located in southern Siberia.

Methane clathrates can be found in polar regions, both in offshore and onshore sediments. These occur in Alaska, Siberia and Northern Canada, e.g.: at the Mallik gas hydrate site in the Mackenzie Delta. Fig.4 There are also some hypotheses that methane clathrates can be found beyond Earth, for instance on comets or ice moons such as Europa, Titan and Enceladus. Some scientists also speculate that methane found on Mars might be that from which the gas hydrates originate.

To calculate amounts of methane hydrate, the scientists estimate the quantity of carbon contained in gas hydrates. Therefore, they can compare deposits of methane hydrates to oil and natural

Patrycja Lanc

57

Fig. 4 - Map of locations where gas hydrate has been recovered and inferred [USGS Gas Hydrates Project]

gas resources. But there are lots of factors that may affect the result and which have to be taken into account by the scientists. The most recent estimates are in the order of 500 to 1500 gigatons of carbon. This amount exceeds the reserves of natural gas, nowadays projected at around 100 gigatons of carbon. This calculation makes the deposits of methane clathrates of major interest as a potential energy source.

Potential environmental impacts

While methane hydrate resources may appear to be a new future for energy industry, it is considered that extraction or even just their presence may have considerably detrimental impact on the climate.

One of the main concerns about methane hydrates is the danger of catastrophic release of methane to the atmosphere from the decomposition of its deposits. It can lead to a global climate change, due to fact that methane is a greenhouse gas and is considered to be about 20 times more harmful than carbon dioxide. A hydrate breakdown can be caused by raising the temperature of oceans or

even by extracting the hydrate. Due to this risk, the scientists recommend the mining of methane hydrates only when it is covered by a thick layer of sediments of around 100m.

Moreover, gas hydrates are perceived as cement to sediments and therefore they have a significant effect on sentiment strength. Their breakdown may cause massive underwater landslides, which can lead to tsunamis, earthquakes and also the already-mentioned methane release. Fig. 5 Those possible obstacles have a massive impact on a potential extraction, making it more challenging for gas and oil industry. However, methane is a clean-burning gas; its extraction from hydrates might displace coal consumption in countries such as India or China.

Methods and attempts of extraction

The extraction methods for methane hydrates, such as thermal stimulation, depressurization, or solvent injection, are still in development. Some of them have some similarities to gas and oil extraction. However, gas hydrates do not act as

SPRINGâ&#x20AC;&#x2030;/â&#x20AC;&#x2030;2016

ď&#x192;&#x192;

ď&#x192;&#x192;

58

these conventional fuels. Oil and natural gas flow naturally through the pores of the reservoirs to the well. Hydrates, on the other hand, are solid, and must first be dissociated before the methane gas can be extracted.

The first method, called thermal stimulation, can be performed by water circulation. In this case, the engineers drill a well so that they can pump hot water into the deposits. The hot fluid raises the temperature to the point that the gas hydrates break and release the methane. However, after having conducted some tests in 1998, 2002 and 2007/2008 in the permafrost of the Mackenzie River Delta in Northwest Canada, this method was evaluated as more expensive and harder to perform than the depressurization method. The

Methane hydrates â&#x20AC;&#x201C; the new energy source?

program involved partners from five countries, among others from Canada, Germany and Japan.

In 2002 they undertook a full-scale gas hydrate production by thermal heating from the Mallik well, achieving only a modest gas flow. In the following years they returned to the site to test the method of depressurization, and succeeded in achieving a sustained gas flow.

Another important step forward in gas hydrate research was the Ignik Sikumi well project on the north slope of Alaska, executed by the U.S Department of Energy together with ConocoPhillips and the Japan Oil, Gas and Metals National Corporation in 2011â&#x20AC;&#x201C;2012. The project was designed to investigate a production method in which a mixture of carbon dioxide and nitrogen

Fig. 5 - Illustration of what happens when a slope failure occurs above a gas hydrate layer [3]

Patrycja Lanc

59

injected into a gas hydrate-bearing rock unit could release methane while sequestering carbon dioxide in hydrate form. This method would serve a dual purpose of both producing natural gas and sequestering carbon dioxide. It is a win-win solution. What’s more, the use of this technique could enable the exploitation of hydrate deposits without any impact on the mechanical stability of the deposits. The test confirms that such mixture of nitrogen and carbon dioxide can be effective in methane production; moreover, it provides new data for future development.

gas. In the layers of methane hydrates prevails high pressure, caused by surging over deposits of sediments and water. By drilling a well from the surface, they get a pressure drop, which slowly dissociates hydrates and turn solid crystalline lattice into liquid water releasing the enclosed methane. This was a great accomplishment for resource-poor Japan, which made it potentially possible for the country to reduce its dependence on import.

Meanwhile, Japan achieves its first gas flow extraction from offshore methane hydrate in March 2013 from the Nankai Trough, an ocean basin 80 kilometers off the coast of Japan. The Japanese energy organization ( JOGMEC) estimates that in this location there are about 1.1 trillion cubic metres of methane trapped in gas hydrates. Those deposits are equivalent to, more or less, the amount of LNG imported by Japan within 11 years. To release the methane, the engineers used a depressurization method that turns methane hydrate into methane

Despite Japan’s great success in producing gas from undersea hydrates and conducted tests by the U.S. Department of Energy, there is still much work to be done to develop profitable and effective methods of methane hydrates extraction. However, the world’s demand for energy continues to increase rapidly. Facing the possibility of exhausting conventional sources of energy, methane hydrates may have a bright future, eventually they are believed to be the world’s largest source of carbon. 

The future

References 1. Bailey, A. (2015, April 26) Promising results. DOE publishes more findings from North Slope methane hydrate test well. Petroleum News. Retrieved March 10, 2016, from http://www.petroleumnews.com/ pntruncate/512154321.shtml 2. Fox, L., Spalding, D. (2014, May 7) Challenges Of Methane Hydrates. Retrieved March 15, 2016, from http://www.ogfj.com/articles/print/volume-11/issue-5/features/challenges-of-methane-hydrates. html 3. Henriet J.-P., Mienert J. Kvenvolden K.(1998), A primer on the geological occurrence of gas hydrate Gas hydrates:relevance to world margin stability and climate change Henriet J.-P., Mienert J. Geological Society Special Publication no. 137, pp. 9–30 London, UK Geological Society 4. Hołdys, A. (2013, February 25) Hydraty – paliwo przyszłości?. Retrieved March 10, 2016 from http:// www.wiz.pl/8,853.html 5. Maslin, M., Owen, M., Betts, R., Day, S., Jones, T.D., Ridgwell, A.,(2010, April 19) Gas hydrates: past and future geohazard?, Retrieved March 20, 2016 from http://rsta.royalsocietypublishing.org/content/368/1919/2369 6. Paull C. K., Dillon W. P.Kvenvolden K. A., Lorenson T. D. 2001 The global occurrence of natural gas hydrates Natural gas hydrates:occurrence, distribution and detection eds Paull C. K., Dillon W. P. AGU Geophysical Monograph 124 3 18 Washington, DC American Geographical Society

SPRING / 2016





60

Methane hydrates – the new energy source?

7. “Fiery Ice”, Lower Production and Transportation Costs. nd. Retrieved March 15, 2016, from http:// www.mes.co.jp/english/mes_technology/ngh.html 8. Gas Hydrate Studies - a part of the geophysics group.(2012, July 15), Retrieved March 10, 2016, from http://web.archive.org/web/20120615023448/http://woodshole.er.usgs.gov/project-pages/hydrates/ index.html 9. Methane hydrates. Retrieved (2000, June), Retrieved March 10, 2016, from http://web.ornl.gov/info/ reporter/no16/methane.htm 10. Successful Test of Gas Hydrate Production Test Well Ignik Sikumi on Alaska’s North Slope. (2012, May 24), Retrieved March 10, 2016, from http://energy.usgs.gov/GeneralInfo/EnergyNewsroomAll/TabId/770/ArtMID/3941/ArticleID/812/Successful-Test-of-Gas-Hydrate-Production-Test-Well-Ignik-Sikumi-on-Alaskas-North-Slope.aspx 11. World Ocean Review, Marine Resources – Opportunities and Risks, 3-Energy from burning ice,(2014), Retrieved March 15, 2016, from http://worldoceanreview.com/en/wor-3-overview/methane-hydrate/

B. Bosbach, G. Lingenfelder, J. Röth, F. Tillmans, M. van Veen



61

Achimov Gas – Condensate Production Benjamin Bosbach, Georg Lingenfelder, Joschka Röth, Fabian Tillmans, Marco van Veen

**RWTH Aachen University ÞÞGermany benjamin.bosbach@rwth-aachen.de, georg.lingenfelder@rwth-aachen.de, joschka.roeth@rwth-aachen.de, fabian.tillmans@rwth-aachen.de, marco.vanveen@rwth-aachen.de  University  Country  E-mail The Schlumberger Business Case challenge was performed during the 1st International Oil and Gas Majoring Students Forum, held in Moscow end of February. Real data and tasks were provided by Schlumberger. The competition amongst about 100 students from different parts of the world – all related to petroleum-sciences – was supervised by representatives from the industry. While the main task was to come up with innovative technical solutions for the production of gas condensates from the Achimov formation in North West Siberia, further evaluation criteria were the overall performance of the team as well as the ability to understand and handle complex issues in a short time. The jury highlighted our outstanding teamwork during the competition, the use of additional papers and the well-structured way we approached the tasks.

Introduction

From Feb 28th until Mar 6th 2016 our team of RWTH Aachen University participated in the 1st International Oil and Gas Majoring Students Forum "New Generation: Across the Universe," held

at Gubkin Russian State University of Oil & Gas in Moscow. As part of the conference, a business case organized by Schlumberger and Changellenge had to be solved by the participants. The basic facts were provided already in advance of the event.

In this article, firstly, a broad overview of the case will be given, to continue with the presentation of an individual solution and a description of our strategies and performance during the case.

Achimov Formation Geology

Generally, the Achimov formation consists of turbidite and slope facies. Main reservoir units are sandstones and siltstones. Deposited in Neocomian age (Early Cretaceous), the formation nowadays lies at depths of about 3500 - 3800 m.

The reservoir sandstones consist of argillaceous and calcite cement and are mainly arkosic. Typical mineralogy is 40-55% feldspar, 25-40% quartz and 5-20% rock fragments (Borodkin et al., 2001).

Leonenko and Karnyushina (1988) stated that the formation had undergone strong compaction as well as diagenetic alterations, which are primarily quartz overgrowth and calcite dissolution. Typical for the Achimov formation are multiple lens-like sandstone bodies which form the reservoir units.

This morphology, typical for turbidites, comprises the problem of strong lateral heterogeneity (Borodkin et al., 2001). Porosities in those sandstones are moderate, around 16% whereas permeability is low and sometimes even very low with an average value of 0.6 to 1.5 mD, depending on the layer of the formation. Sandstone beds are several meters

SPRING / 2016





Achimov Gas – Condensate Production

62

After Dobrokhleb et al. (2014) ÈÈ

ÈÈ ÈÈ

ÈÈ

ÈÈ

ÈÈ

ÈÈ

Abnormally high initial reservoir pressure (590 – 610 bar) at a depth of 3800 m High reservoir temperatures (105 – 1 15°C) Low- to very-low-permeability rocks (0.1 – 10 mD) High content of condensates (275 – 320 g/m³) Simultaneous occurrence in strata condensate content gas and oil Tectonic fragmentation of individual sections of deposits Administrative division of the common hydrocarbon reservoir in accordance with the licensed area.

After Graf (2014) ÈÈ

ÈÈ

ÈÈ

ÈÈ

ÈÈ

ÈÈ ÈÈ

ÈÈ ÈÈ

ÈÈ

ÈÈ

Tab. 1 - Manifold challenges of Achimov Formation

Logistics, such as the hostile operational environment and the alignment of stakeholders Well construction risks due to high overpressure in the formation and permafrost at the surface Extreme Reservoir Properties resulting from the turbidite system Poor formation quality with strongly varying permeabilities from one reservoir layer to another Heterogeneity of reservoir properties between wells Compartmentalization and connectivity Limited fracture growth due to either extreme reservoir heterogeneity or an isotropic (relaxed) stress regime Uncertain production environment Reduced well productivity due to liquid fall-back, as dew point pressure of gas condensate is 20 – 50 % below initial reservoir pressure Affinity to paraffin precipitation in production tubing and at the surface (Ignatyev et al., 2011) Back-allocation and reserves accounting as fracking Ach5 could result in producing from Ach3,4 as well

B. Bosbach, G. Lingenfelder, J. Röth, F. Tillmans, M. van Veen

63

Fig. 1 - Phase diagram of a gas-condensate system as found in the Achimov Formation (Changellenge, 2016).

thick and often interlayered with shale units.

Those shales separate the Achimov formation in lithology but not hydrodynamically as fluid and pressure properties in reservoir units Ach3 and Ach4 appear to be the same. While Ach3 and Ach4 are somehow connected in means of hydrodynamics, Ach5 and Ach6 show no connectivity to shallower reservoir units (Graf, 2014). Reservoir fluids are rich gas-condensates with a condensate content varying from 280 to 380 g/m³ (Descubes, 2012), but samples have also indicated gas-condensate contents of up to 450 g/m³, which makes the production more economical (Graf, 2014).

High formation temperatures (up to 115°C) and extreme formation pressure (about 600 bar) are major challenges in production (Descubes, 2012).

presented in the case is the liquid fall-back caused by changing temperature-pressure conditions influencing the phases of the gas-condensate system. The physical principle underlying this phenomenon is sketched in Fig.1.

Solutions

Challenges

To tackle these challenges, optimal technical solutions needed to be found. A broad range of existing and field-tested technologies could be used. Therefore, all the involved players (service companies, operator and drilling contractor) conducted the planning phase together by using a risk assessment-based approach and set up a drilling program (Dobrokhleb et al., 2014). The prioritized solutions found and already applied will be described briefly.

Achimov formation is considered to be one of the most challenging and complex fields of development (Dobrokhleb et al., 2014). Table 1 gives an overview of the challenges which come along with the objective to produce gas from the Achimov field. One of the main challenges

In the encountered pressure-stress regimes, to keep the equivalent circulating density (ECD) low and prevent major accidents while drilling, the influencing factors were identified in a sensitivity analysis. Beside the diameter of the drill string and the mud weight, the drilling fluid rheology

SPRING / 2016





Achimov Gas – Condensate Production

64

Fig. 2 - The winning team of RWTH Aachen University together with Rector Viktor Martynov and Counsellor Anatoly Zolotukhin.

was the main factor to be optimized. A weighted oil-based mud (OBM) with low viscosity and a flat rheological profile was chosen. Because of the low flow of mud circulation and to ensure effective hole cleaning, a special bottom hole assembly (BHA) was required. Therefore, rotary steerable systems (RSS) were combined with optimally-balanced PDC drill bits to provide maximum steerability (Dobrokhleb et al., 2014).

heterogeneity of drilled rock formations (Dobrokhleb et al., 2014).

Along with these existing specialised solutions, the finalists of the business case all agreed on the following aspects regarding the production of gas-condensate from Achimov formation in their presentations: ÈÈ

To predict the drilling conditions and determine the ECD parameter, pre-drill geomechanical and wellbore-stability models were established by using logging data from offset wells. This was supplemented by real-time monitoring and evaluation of the existing models while drilling (LWD). Units for broadband sonic, density and neutron were included into the BHA . This elaborate improvement became necessary due to a narrow safe window of ECD and the complex

ÈÈ ÈÈ

continuing with hydraulic fracturing (according to Marino et al., 2010) avoiding large number of wells idea of (sub-) horizontal wells

Coming to innovative ideas for the future, we looked at the issue of wellbore blocking due to liquid fall-back. It occurs when the reservoir pressure drops below the dew point of the gas condensate.

The liquid phase starts to condense, which leads to a two-phase region. As soon as the fluid in the well

B. Bosbach, G. Lingenfelder, J. Röth, F. Tillmans, M. van Veen

is not able to bring up the liquid anymore, it starts to fall back and gradually block the well (compare Fig. 1). The consequence is obvious – we will have a massive decrease in productivity. According to Graf (2014), 3 out of 10 wells will cease in their production within the first five years if they are completed in poor formation quality. To prevent the borehole of getting blocked, we need to find a way to avoid the two-phase region and increase the reservoir pressure to bring the liquids up. A reasonable option could be the drilling of injection wells to control the reservoir pressure by injecting carbon dioxide or dry gas. This method is expensive but really promising regarding the increase of production rate. Not only at an advanced stage of production, but also at the beginning, as Graf (2014) showed, the condensate banks can start to establish even within the first year.

Another idea to enhance the gas recovery is to adopt a solution of surfactants in order to lower the interfacial tension. Furthermore, we thought about the possibility of using an In-well separator to avoid the two-phase region at the bottom of the borehole. The technology for this idea does not exist yet but could be interesting for the future.

Performance during the Schlumberger Business Case About the Schlumberger Business Case

The Schlumberger Business Case took place on Feb 28th, 2016. 95 international students from 35 countries were grouped up by the organization committee for the semi-finals. Four separate clusters consisted of five teams (one cluster with four teams) and each team had five participants.

There were two periods of presentation. First the semi-final, when each cluster had to announce their winning team, and second the final, when the clusters had to compete against each other. For

65

the first round we were given about three hours to prepare a five-minute presentation in which we summed up our solutions for the following tasks: ÈÈ

ÈÈ

ÈÈ

Assessment of the main issues of the existing technological solutions Identification of the most effective existing technological solution and the proposal of new technological solutions for a step improvement in well completions type for the Achimov gas-condensate formation and the justification of our choice.

Definition of technical/engineering value of additional data acquisition, based on the chosen technological solution, required investments and possible risks.

As the circumstances in the Achimov formation are quite tricky, two mentors were present during the preparation time. Mr Anton Ablaev and Mr Vyacheslav Kretsul, both Schlumberger Business Development Managers, were not only the mentors of our cluster, but also the judges for the semi-final.

After literally setting up the first presentation until the very last seconds of the deadline, every group had to get on stage to present their innovative ideas and defend them in a short Q&A session afterwards. The presentations were as diverse as the individual teams. At this point we want to mention the flashing performance of Team #4 from our cluster. They combined fundamental knowledge in various fields relevant for production with numerical simulations. Nevertheless, the presentation of Team #1 (from RWTH Aachen University, Germany, shown in Fig. 1) was most convincing for the judges.

The next half an hour was scheduled for gathering all important information and knowledge from the red cluster’s teams to include in our final presentation. The presentation was again determined to be within a strict five-minute frame. This time the judges were Kreso-Kurt Butula (Schlumberger, Unconventional Reservoirs

SPRING / 2016





66

Business Development Manager Russia & Central Asia), Marina Bulova (Schlumberger Moscow, Research Director), Aydin Karimov (Schlumberger, Human Resources Manager), Viktor Georgievich Martynov (Rector of Gubkin University and member of Gazprom Board of Directors) and Anatoly Zolotukhin (Counsellor of International Affairs of Gubkin University).

Based on the good introduction of our team, the correct citations, excellent team work, a convincing and well-prepared presentation as well as a good performance in the Q&A session, the finalists from the red cluster were chosen as the winning team.

Our Challenges

Most challenging for us were the technical issues we had to deal with. As all of our team members are geologists, usually our main tasks are done when it comes to production, so we had some struggle finding our way into the topic. Therefore our expectations were really down-to-earth and we knew we had to put in a lot of effort to keep up with the others. The basic idea behind our success is that if you do not know how to tackle a problem, find someone who knows. We experienced great support during the preparation of our presentation. In the semi-finals our mentors Mr Ablaev and Mr Kretsul, who both did a great job with helping us staying on the right track.

They asked the right questions about what we were doing so we started to overthink and develop our ideas. Dividing the tasks and building up competence groups made us work more efficiently. We discussed the proceedings frequently and asked our mentors for help or guidance whenever we got stuck. During the preparation for the final presentation it was absolutely amazing how the entire red cluster supported us with their ideas and knowledge. The tight time limit was tough as well.

Another challenging factor was getting access to publications with additional relevant information to verify our ideas on a professional basis. Sudden technical issues with the Wi-Fi connection made

Achimov Gas – Condensate Production

us use our improvisation skills (compare Fig 3).

Luckily, one of our team members was clever enough to organize a Russian SIM card with an Internet plan before arriving in Moscow. So we set up a Wi-Fi hotspot for our mobile phones and laptops to connect with. Via a VPN client we got access to onepetro.org and then had access to relevant SPE papers. But what happens when several mobile phones and laptops access the internet via a mobile Wi-Fi hotspot and download papers of several megabytes in size? - it takes very long for the download to complete. And at that point we did not know whether the just-downloaded papers would turn out to be useful or not. But we were lucky again with the first three papers we accessed. They contained the information we needed, in addition to the material that was provided for preparing our solution to the business case.

Take-Home-Message

In the passage above we explained some challenges we had experienced during the fascinating event of the Schlumberger Business Case challenge. We have also shown different ways to tackle these challenges and to overcome the back-breaking thoughts of having no chance.

Working on the problems regarding production from the Achimov formation, we found out that as an individual you don´t even have the slightest chance to survive the challenging atmosphere.

Only as a team you can combine your competences and strengths to make the most of it. People around you often have a similar opinion about a certain problem, but listening to those who disagree will provide you with essential information. That’s when discussions start and ideas are being developed. The famous saying that a team is only as strong as its weakest player is really important when it comes to dividing the tasks.

Everybody has their strengths and weaknesses and by finding the right niche for each player to contribute their full strength you can achieve the strongest possible version of the team. Mr Anatoly Zolotukhin found the exact words to describe the way to achieve success when saying “Try to

B. Bosbach, G. Lingenfelder, J. Röth, F. Tillmans, M. van Veen

67

Acknowledgements

work with smart people.” And to be honest, that is all what tackling a problem is about. There will always be people smarter and more experienced than you are. Besides that, giving up is never an option. Not even for geologists facing a problem regarding production of gas-condensate from HPHT-formations. If you get stuck, it should be your primary aim to find smart people and to ask them for support. We experienced a lot of support from our fellow teams from the red cluster, from our mentors and from everyone who got involved in the Q&A sessions. Thanks to their feedback, we carried out fruitful discussions and gained valuable experiences.

At the end we would like to say “thank you” to the entire Organizing Committee of the “New Generations: Across the Universe, 1st Oil and Gas Majoring Students Forum” for their effort in organizing and conducting such an amazing event. We are thankful to the German Section SPE (GSSPE) for financial support of our trip.

Thanks a lot, Schlumberger and Changellenge, for providing the data, a big amount of working hours of the jury and for conducting the Business Case.

Again, thanks to everyone who was supporting our team during the Business Case, especially our mentors Mr Ablaev and Mr Kretsul but also all the participants of the red cluster. 

Fig. 3 - Improvisation was a major skill required during the case competition.

SPRING / 2016





68

Achimov Gas – Condensate Production

References 1. Borodkin, V. N., Brekhuntsov, A. M., & Deshenya, N. P. (2001). Framework, depositional conditions, and petroleum productivity of reservoirs of the Achimov Formation and its shelf equivalents in the Urengoy area: Geologiya. Geofizika, i Razrabotka Neftyanykh Mestorozhdeniy, (5), 16-24.

2. Changellenge (2016). Achimov formation: project of a gas-condensate stratum production optimization. Presented to the participants of the International Oil and Gas Majoring Students Forum.

3. Descubes, E. (2012). Stochastic Uncertainty Analysis in Compositional Simulation for Giant Gas-Condensate Field Reservoir Performance Prediction (Russian). In SPE Russian Oil and Gas Exploration and Production Technical Conference and Exhibition. Society of Petroleum Engineers. SPE-162045.

4. Dobrokhleb, P., Ablaev, A., Chetverikov, D., Zavarigin, S., Inyushina, A., Petrakov, Y., Sobolev, A., Zadvornov, D., Tarasov, O., Milushkin, A., Milenkiy, A., Grigoryev, M., & Sidorov, D. (2014). Best Practice of Horizontal Well Construction Operations for the Challenging, High-Pressure Achimov Formation-Urengoyskoe Field. In SPE Russian Oil and Gas Exploration & Production Technical Conference and Exhibition. Society of Petroleum Engineers. SPE-171265-MS. 5. Graf, T. (2014). Vertical and horizontal Integration to overcome extreme Operational Challenges for the Achimov tight, gas-condensate Formation. In SPE Russian Oil and Gas Exploration & Production Technical Conference and Exhibition. Society of Petroleum Engineers. SPE-171169-MS. 6. Ignatyev, A. E., Mukminov, I., Vikulova, E. A., & Pepelyayev, R. V. (2011). Multistage Hydraulic Fracturing in Horizontal Wells as a Method for the Effective Development of Gas-Condensate Fields in the Arctic Region (Russian). Society of Petroleum Engineers. doi:10.2118/149925-RU 7. Leonenko, G.N., & Karnyushina, E.E., (1988). Regularities in changes of reservoir properties with depth in West Siberia and efficiency of penetration of reservoirs. in Medvedsky, R.I., ed., Physico-lithological characteristics and reservoir properties of productive, deeply buried rocks of West Siberia (Fiziko-litologicheskiye osobennosti i kollektorskiye svoystva productivnykh porod glubokikh gorizontov Zapadnoy Sibiri): Tyumen, Russia, ZapSibNIGNI, p. 96–104.

8. Marino, S., Butula, K. K., Mauth, K. D., Mullen, K., Volokitin, Y., Ishmeev, T., & Khabarov, A. (2010).

Integrated Approach to Hydraulic Fracturing of Achimov Formation in Western Siberia. In SPE Russian Oil and Gas Conference and Exhibition. Society of Petroleum Engineers. SPE-136072.