YoungPetro - 2nd Issue - Summer 2011 by Young Petro

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messAGe FrOm THe CHIeF • ABANDONeD DrY WeLLs eAsT meeTs WesT • WOrKING FOr AN OPerATOr

Table of contents

Call for Papers

6 People, engineers and SPE members ɸɸ A letter from Serge Rueff

8 East Meets West AutumnIssue ɸɸ Paweł Wilaszek

A  

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10 Integration of geological, geophysical and YoungPetroiswaitingforYourpaper! completion data to Invetigate Abandoned DryThetopicsofthepapersshouldrefer Wells ɸɸ Kashif Saeed, Kashif Yaqoob

tothosepresentedinthelistbelow:

24 Intensification of high-viscosity oil n production on the example of Yablunivske DrillingEngineering oil-and-gas condenate field

ReservoirEngineering 34 supersonic natural gas dehydration FuelsandEnergy n process compared to teg performance GeologyandGeophysics ɸɸ Tudor F. Precup EnvironmentalProtection 45 Approach for full field scale smart well modeling ManagementandEconomics and optimization ɸɸ Nazarii Hedzyk

ɸɸ Alexey A. Khrulenko

54 Zeolites as natural sorbent in removing Papersshouldbesentto pollutants from drilling waste

papers@youngpetro.org

ɸɸ Dawid Wojaczek

58 Working for an operator ɸɸ Jędrzej Bryła

SubmissionDeadline

8 August 2011

61 The fire within ɸɸ Jakub Slek

63 Oil and Gas Horizons

ɸɸ Dawid Wojaczek Moreinformations

YoungPetro.org/Papers

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Table of contents

Call for Papers

6 People, engineers and SPE members ɸɸ A letter from Serge Rueff

8 East Meets West AutumnIssue ɸɸ Paweł Wilaszek

A  

youngpetro.org/ads ads@youngpetro.org

10 Integration of geological, geophysical and YoungPetroiswaitingforYourpaper! completion data to Invetigate Abandoned DryThetopicsofthepapersshouldrefer Wells ɸɸ Kashif Saeed, Kashif Yaqoob

tothosepresentedinthelistbelow:

24 Intensification of high-viscosity oil n production on the example of Yablunivske DrillingEngineering oil-and-gas condenate field

ɸɸ Alexey A. Khrulenko

54 Zeolites as natural sorbent in removing Papersshouldbesentto pollutants from drilling waste

papers@youngpetro.org

ɸɸ Dawid Wojaczek

58 Working for an operator ɸɸ Jędrzej Bryła

SubmissionDeadline

8 August 2011

61 The fire within ɸɸ Jakub Slek

63 Oil and Gas Horizons

ɸɸ Dawid Wojaczek Moreinformations

YoungPetro.org/Papers

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Intro

Editor-in-Chief

Wojtek Stupka chief@youngpetro.org

Welcome to Petroleum Industry I remember when I first entered door of my lecture hall as well as it was yesterday. In fact I remember the exact first couple of my professor‘s words from that day. 'Please imagine this classroom in the world without oil and gas…' – he said and paused for a minute – '…welcome to Petroleum Industry, the biggest and most important of them all'. Whoever you are, student or Young Professional, you have to know that you are a part of the phenomenon providing world with supply for almost everything you can think of. From the energy propelling your car, through tarmac for the road you are driving on, to the ink without which this magazine could not be printed. Everything people have been producing for nearly last two centuries

was either directly or not, made thanks to the petroleum industry. But as part of it you must not rest on your laurels. The issues world of oil and gas facing now were unknown for our predecessors. Such great rise of energy demands which you can perceive have to result in adequate advancement of technology. Otherwise the consumer’s requests will not be fulfilled. To meet these future goals you have to be in constant motion, progress and progress even more, because any achievement you made works for good of all of us. No matter how cheesy it sounds, it is true. So take an example from your colleagues whose papers are making summer issue and start your work right now! From this place I would like to thank all the people who help us provide you with that magazine, but most of all thank you for being a part of .

Editor-in-Chief

Deputy Editor-in-Chief Bartlomiej Staszkiewicz dchief@youngpetro.org

Editors

editors@youngpetro.org Jakub Jagiello Alexey Khrulenko Lukasz Malinowski Agnieszka Olech Robert Skwara Lukasz Świrk Liliana Trzepizur Pawel Wilaszek Dawid Wojaczek

Art Director

art@youngpetro.org Marek Nogiec

Website Admin

admin@youngpetro.org Kacper Malinowski

Photographers

photo@youngpetro.org Jedrzej Bryla Dawid Jach Krzysztof A. Fugiel

Chapter supervisor Dariusz Knez PhD

Advertising

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Partner

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Intro

Editor-in-Chief

Wojtek Stupka chief@youngpetro.org

Editor-in-Chief

Deputy Editor-in-Chief Bartlomiej Staszkiewicz dchief@youngpetro.org

Editors

editors@youngpetro.org Jakub Jagiello Alexey Khrulenko Lukasz Malinowski Agnieszka Olech Robert Skwara Lukasz Świrk Liliana Trzepizur Pawel Wilaszek Dawid Wojaczek

Art Director

art@youngpetro.org Marek Nogiec

Website Admin

admin@youngpetro.org Kacper Malinowski

Photographers

photo@youngpetro.org Jedrzej Bryla Dawid Jach Krzysztof A. Fugiel

Chapter supervisor Dariusz Knez PhD

Advertising

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Partner

summer / 2 011

Letter

People, Engineers and SPE Members Member of the Board of Directors of the Society of Petroleum Engineers International Regional Director of South, Central and East Europe

People, this is what we engineers and spe Members do not take care enough. We are people first, then engineers, then spe Members. People come always first. I have attended and participated to the Offshore Technology Conference of Houston, Texas, for the last 20 years. Each and every year there are panel discussions, presentations of hundreds of papers and also multiple poster sessions from service companies and contractors. They all discuss, report and comment on techniques, methods, budgets and projects but also on all kinds of problems such as delays in completion (of wells, of projects, etc.), repair times, failures of equipment (not seldom enough reported), stand-bye times. What is behind all this ? People.

ʇʇ a letter from the director

Serge Rueff, PhD

2011 is now called « The Year of the People » because what has happened and is happening in North Africa and in Middle East. Poland had already its Year of the People…. some 30 years ago but information technology was not that immensely developed at this time as it is today and your liberation movement did not splash the World as those of today do. But you made it very successfully: Poland became a democracy, thanks to your people.

People, Engineers and SPE Members

Houston is full of engineering « think tanks ». The buildings of such engineering companies as Technip, Worley Parsons, Brown and Root, Coots, Mustang and Sercel for instance are as big as the buildings of Conoco-Phillips, Devon or BP. What is populating these buildings? People. There are as many engineers in consulting companies such as Gaffney and Cline, Knowledge Reservoir and DeGolyer and MacNaughton as in the Operators offices. What is populating these companies? People. Yes, I heavily insist on people. Our education, then our working life, do not recognize enough that we are dealing with people before than dealing with engineers and with s p e Members. We as people we have our family background, our environment, our education, and then later on we have our family life – husband or wife, and kids. All this create and induce satisfaction and dissatisfaction, pleasures and pains, happiness and madness. Whatever our professionalism, all this directly impacts our work as engineers and our behavior as s p e Members. If we have problems at home we cannot concentrate on our work, and if our Wife

or Husband needs us at home we cannot be a good volunteer for s p e . I am personally pushing for an extended spread of integrated multidisciplinary project management teams. But if one does not like any other member of this team the project will then most likely go wrong as the individual thinkings will not integrate. This was most likely situation that was at the origin of the Macondo catastrophe. We learn a lot at school then at university, but we do not learn how to work with people, how to understand our coworkers. This is not a matter of psycho-

analyze (!...), but just a matter of care. We must care for people and show it. Then the work, the project, will be enjoyable and most likely successful. When you compete with other students in the course of paper contests, then later on with your co-workers for obtaining a promotion, or with other s p e Members for getting an award, please be fair, please care for your competitors. The competition will then be fun and the winner will deserve the glory and your faithful support. Care, and people will give you more in return than you can ever dream. Serge Rueff, PhD

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Letter

People, Engineers and SPE Members Member of the Board of Directors of the Society of Petroleum Engineers International Regional Director of South, Central and East Europe

ʇʇ a letter from the director

Serge Rueff, PhD

People, Engineers and SPE Members

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East meets West

Pawel Wilaszek AGH UST

East meets West After succeeding with the 1st edition of ‘East meets West’ everyone was convinced that our SPE Student Chapter needs to follow it up. A very long and difficult year of preparation resulted with brand new quality of event – European Student Petroleum Congress. From the 13th till the 15th of April 2011 the most popular Polish city – Krakow – once again became the technical heart of the Europe. We managed to gather students, academic professors and professionals from the whole continent, and even further. The first day of the Congress joined a Student Debate concerning ‘Conventional and Unconventional Gas’. Young people from all over Europe presented their points of view, exchanged ideas and discussed them with other colleagues. They were also able to hear some lectures referring this topic given by professionals who shared some priceless knowledge about this case. In the afternoon each SPE Student Chapter had a chance to present their activities, challenges and development plans. The day

ended with an Icebreaker Party in Tawo Restaurant. On Thursday a Company Day was established. In the first sessions the invited companies were given a possibility to speak about their achievements, challenges taken and career opportunities. Congress guests heard presentations from such companies as Halliburton, Schlumberger, Maersk Oil and PGNiG Zielona Góra. In the break a Student Poster Session was established. Among ten well prepared posters, the one worked out by Alexey Khrulenko from Gubkin University of Moscow was chosen to be the winner of the Session. During the second session technical papers were presented. Professionals from Halliburton, Schlumberger, Weatherford and Baker Hughes presented the modern technologies applied in the industry, recently carried out surveys and prospects for the future. At the end of the day an Official Banquet was held, which took place in the Kompania Kuflowa ‘Pod Wawelem’. The third day of the Congress was covered with Student Paper Contest. During the whole day the invited students were showing results of their research. Each of the nineteen presenta-

tions was on a very high level, and once it was very hard to judge them, speaker from University of Clausthal – Kashif Saeed appeared to be the winner. The second place was for Nazarii Hedzyk from Ivano-Frankivsk, and the third for Georgina Kovacs-Lukoczki from University of Pecs. After the closing ceremony there was a time for a student party in Diva Music Gallery. During the whole Congress we were pleasured to host about 600 guests. We can be especially proud of a very big contingent of students from such countries like France, Denmark, Norway, Germany, Czech Republic, Hungary, Romania, Ukraine and Russia. Of course the things couldn’t happen without support of our generous sponsors: Halliburton, Schlumberger, Eni International Resources, Aurelian Oil, Maersk Oil, Cameron, PGNiG Zielona Góra and Mr Naseer Bashar. We would like to express our

words of gratitude to Congress Partners – PGNiG Ignacy Łukasiewicz Foundation and Drilling, Oil, Gas – Science and Traditions Foundation and OGEC Kraków which sponsored special awards for students taking part in Poster Session and Paper Contest. It was a great pleasure and honor for us to host these all people here in Krakow. Every warm word that we heard about the Congress made us certain that such events have great potential and assured us that ‘East meets West’ Congress will stay in hearts of the participants for the long time. From this place we are very proud and happy to announce that in the coming year 2012 the next Congress will be organized and we hope to meet you all once again in Krakow – the city where ‘East meets West’.

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East meets West

Pawel Wilaszek AGH UST

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Papers

Integration of Geological, Geophysical, and Completion Data to Investigate Abandoned Dry Wells. A Case Study

Kashif Yaqoob Specialist Geosciences Data Management, Mubadala Oil & Gas, UAE myaqoob@mubadala.ae

Kashif Saeed, Kashif Yaqoob

and fold-thrust belt provenances was transported into delta and dispersed by fluvial and wave processes. Basin fill is related to cyclic delta top and delta front deposits, low stand canyon incisions and fan progradation, and high stand deposition in canyons and on the shelf (Abdul Waheed, 2003). The Indus River is about 2.900 km’s long and travels about 1.200 kms in the plains after leaving the high mountains with the total drainage area of 966.000 sq. kms. There are four

2. A Late Tertiary subsided paleo-depression area in the centre with down to basin normal, growth, listric faults and associated rollover anticlines; 3. Shale diapiric structures to the west; and 4. An en-echelon folded segment adjacent to the eastern side of the Murray Ridge. Regional studies in the Northern Indian Ocean and high Asia shows that

Lessons learned are one of the important assets in the exploration and production industry. Keeping that in view, the current work focuses on the integration of geological, geophysical, and completion data in order to investigate the PakCan–01 well, which is the only well in Offshore Indus Basin, PakCan–01 showing gas but there was no economic discovery. The work involves the indepth post well review of the PakCan–01 well, Indus Offshore, Pakistan, with the focus on integration of geological, geophysical, and completion data. The supplementary work includes the study of petroleum system

including source, reservoir, seal/cap, maturity, trapping mechanisms, and stratigraphy of Offshore Indus Basin as a whole. The presented work helps in the determination of lithology, structure, and also the potential reasons of failure of PakCan–01 well, with prediction of hydrocarbon accumulations, maturity and extent of source rocks. Offshore Indus Basin, Pakistan is by far the under-explored sedimentary basin of Pakistan and no economic discovery has been made so far, however only gas shows were observed in PakCan–01 well but these were not of economic significance. Cretaceous and younger stratigraphy is encountered in exploratory wells of Indus Offshore. Sembar, Goru, Mughalkot, Pab, Khadro, Bara, LakiGazij, Kirthar, Nari, Gaj formations are encountered in wells explored fol-

lowed by Siwalik Group. Shales, limestones, and argillaceous layers of Gaj, Nari, Laki, Ranikot, and Mughalkot formations are main petroleum source rocks where as sandstones and limestones of Gaj, Nari, Kirthar, and Ranikot formations are acting as the main reservoir rocks in the basin. The intercalated shales and compact limestones act as seal/cap rock. Isopach maps and migration fairway models give a better understanding of hydrocarbon generation and migration. A detailed post well analysis including well–velocity survey analysis, structural and stratigraphical interpretation, regional geological models, geothermal analysis, and burial history curves help in further exploration and drilling activities in the Indus Offshore, Pakistan.

ically quiescent passive margin. Maximum delta progradation and fan building occurred during Late Tertiary, a period coincident with the head-on collision between Indo-Pakistan and Eurasian Plates, the subsequent massive uplift and unroofing of Himalayas. Mainly quartz-rich detritus of recycled orogen

main structural features which are delineated within the sedimentary sequences of this basin (Jaswal and Maqsood, 2002) namely:

the drilling on the Indian Ocean submarine fans has for a long time been considered difficult or impossible because of limitations in drilling technology, despite important advances based on earlier shallow-penetration drilling (Fig. 1). Integrated Ocean Drilling Program (IODP) and the Deep Sea Drilling

8Abstract8

ɨɨ Introduction The Offshore Indus Basin of Pakistan is located between the coordinates 64° 25´ E to 68° 10´ E and 23° 00´ N to 25° 00´ N in the east of Murray Ridge covering an area of about 90.000–240.000 sq. km (Baluch and Quirk, 1998). The Murray Ridge-Owen Fracture Zone marks the western extremity of the basin and is the separation of the Indus Offshore and Markran Offshore, Pakistan. It extends in the east towards western coastline of the Indo-Pakistan subcontinent. Indus Offshore basin is a vast but under explored area of Pakistan. The geological boundaries of the Offshore Indus extend up to DabboCreek Anticline in the northeast, failed Kutch Rift Basin in east, Murray Ridge in the northwest and west, and southern boundary is taken along significant lobes of delta (Fig. 1). The Offshore Indus Basin of Pakistan resulted from the development of a passive margin in Late Cretaceous and continent-continent collision in Late Cenozoic. Early sediments were derived from mildly uplifted orogenic fronts (due to initial oblique collision) and the tecton-

Kashif Saeed Technische Universität Clausthal, Germany Kashif.Saeed@tu-clausthal.de

Integration of Geological, Geophysical, and Completion Data

1. The tilted fault blocks related with a rift system in the east below a Tertiary Platform

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Papers

Integration of Geological, Geophysical, and Completion Data to Investigate Abandoned Dry Wells. A Case Study

Kashif Yaqoob Specialist Geosciences Data Management, Mubadala Oil & Gas, UAE myaqoob@mubadala.ae

Kashif Saeed, Kashif Yaqoob

main structural features which are delineated within the sedimentary sequences of this basin (Jaswal and Maqsood, 2002) namely:

8Abstract8

Kashif Saeed Technische Universität Clausthal, Germany Kashif.Saeed@tu-clausthal.de

Integration of Geological, Geophysical, and Completion Data

1. The tilted fault blocks related with a rift system in the east below a Tertiary Platform

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Kashif Saeed, Kashif Yaqoob

Integration of Geological, Geophysical, and Completion Data

Projects (DSDP) have came up with the new enhanced riser drilling capability as it opens new opportunities for deep penetration at a time when the science of climate-tectonic interactions has reached the point where workable hypotheses can be tested. The Indian Ocean remains the classic area to study such interactions because of the proposed coupling between the growth of the Himalaya and Tibet and the strengthening of the Asian monsoon. Between the Murray Ridge in the west and the coast line in the east, there is three fold division of the Indus fan: 1. The offshore deltaic area platform 2. Hinge or transition zone 3. The offshore depression

ɨɨ Tectonic History and Settings

ʈʈ Fig. 1: Regional Bathymetric and topographic map of the northern Indian Ocean and high Asia showing the location (Red Rectangle) and also the existing scientific deep sea drilling sites in the area. The Indus Fan has been outlined (modified after Clift and Molnar, 2003)

Passive margin thermal subsidence in the Early Jurassic resulted in the deposition of a thick succession of fine-grained clastics in western Pakistan. By the Late Jurassic, the combination of widespread passive margin conditions and tectonic quiescence resulted in the establishment of a widespread carbonate platform over most of the country. Continued breakup of Gondwanaland during the Late Jurassic to Early Cretaceous caused gentle uplift of the interior of the Indian Plate, so that Late Jurassic carbonate platform was replaced by shallow marine to deltaic shales and sandstones. Separation of the Indian and Madagascan plates occurred at approximately 90 Ma to 82 Ma. This breakup appeared to have resulted from a shearing movement along the Owen Fracture Zone and its northern extension, The Murray Ridge System which separates the Off-

shore Indus Basin from Offshore Makran Basin,Pakistan (Fig. 2). Tectonically, three plates namely, Indian, Arabian and Eurasian seem to interact directly to shape the sedimentary basins in Pakistan offshore. A fourth plate (African plate) has also contributed in the evolution of these basins in the past. The offshore Indus Basin represents the western part of the trailing edge of the Indian Plate. The Indus offshore is considered as typical Atlantic Type passive margin which is developed as a breakup of Gondwana during the Mesozoic and is across the continental crust of extension of Thar Slope Platform and Kirthar Foredeep. It is cut in the southeastern corner by the submarine canyon of the Indus River. The basin is divided into two tectonic units with hinge zone/shelf limit as the dividing line. The units are: 1. Offshore Depression (in the west) 2. Offshore Platform (in the east) Offshore Depression is between Murray Ridge and hinge zone (66° to 67° E). Here the pot Oligocene sedimentation seems to be nearly continuous. It is represented by thick marine calcarious and terrigenous Miocene clastics, a fairly continuous silty-shaly sequence with lenses of sandstone and bands of limestone. Offshore Platform lies between hinge zone and Pakistan shoreline (67° to 68° E). It may be further divided into two units namely: 1. Karachi Trough offshore platform 2. Thar Slope offshore platform or Indus river deltaic area The boundary between the two is roughly an extension of their onshore boundary.

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Kashif Saeed, Kashif Yaqoob

Integration of Geological, Geophysical, and Completion Data

ɨɨ Tectonic History and Settings

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Kashif Saeed, Kashif Yaqoob

Integration of Geological, Geophysical, and Completion Data

ɨɨ Exploration History All the exploratory wells were drilled by the foreign oil companies in the Indus Offshore area namely Dabbo Creek–01 (Shelf area), Korangi Creek–01 (Shelf area), Patiani Creek–01 (Shelf area), Indus Marine-A1 (Basin area), Indus Marine-B1 (Basin area), Indus Marine C1 (Basin area), Karachi South-A1 (Shelf area), PakCan–01 (Basin area), and Sadaf–01 (Basin area) as displayed in Fig. 3. Mesozoic and Tertiary sedimentary successions have been encountered in these offshore Indus wells. All the wells were abandoned as they proved to be dry although gas shows and traces were found. However, there are prospects of oil and gas in Indus Offshore as the discovery has been made in the Bombay offshore basin (in

Eocene and Miocene sandstone and Limestone) as well as the discovery of Khaskeli oil field by Union Texas, in Early Cretaceous lower Goru sandstone at the depth of about 1.040 m. This field is located 150 Km east of Karachi city in Thar slope. Reinterpretation of seismic data shows Dabbo Creek to have been drilled on the downthrown side of fault block structure, Patiani Creek to be located on the northern flank, while the seismic as well as drilling results don’t justify the presence of east boundary fault providing closure for the trap tested in Karachi South A–1. All the three Indus Marine wells were stopped due to technical difficulties without reaching objective reservoirs.

ʈʈ Fig. 2: Tectonic elements of Offshore Indus, Pakistan. Murray Ridge is boundary between Makran Offshore and Indus Offshore (modified after Raza, 2007)

Karachi trough is generally a rocky area and is characterized by thick post Eocene cretaceous sediments, whereas Thar Slope is mostly covered by alluvium. Post-early Cetaceous sediments are either lacking or thinning out in Thar Slope. Post Oligocene sedimentation seems to have been continuous, except for a short break during late Miocene as encountered in offshore wells. Post Oligocene strata have a maximum thickness of more then 10.660 ft (3.249 m) in Indus marine B–1. Post-early Miocene sediments are missing in Korangi Creek–01, Patiani Creek–01, and Dabbo Creek–01. So the Karachi trough offshore may be divided tectonically as eastern offshore platform and western offshore depression. Structurally the Indus offshore consists of following units:

1. Half graben-extension of Kutch basin 2. A platform area which is considered as prolongation of onshore sindh monocline but it may be a part of Kutch basin due to its similarity of sedimentary rocks encountered in creek wells. 3. A deep depression which may be linked with the onshore depressions, this area is severely faulted by sinous and gravity growth faults. The south western margin of this depression is bounded by a gentle uplift running parallel to the axis of the deep. Huge diapiric features are developed in the west of the depression towards Murray ridge. 4. The fault patterns fit in the regional tectonic setting resulting from northward flight of the Indian plate. And subsequent rifting in its south eastern part.

ʈʈ Fig. 3: Well Location Map of Offshore Indus Basin, Pakistan (modified after Raza, 2007)

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Kashif Saeed, Kashif Yaqoob

Integration of Geological, Geophysical, and Completion Data

ʈʈ Fig. 2: Tectonic elements of Offshore Indus, Pakistan. Murray Ridge is boundary between Makran Offshore and Indus Offshore (modified after Raza, 2007)

ʈʈ Fig. 3: Well Location Map of Offshore Indus Basin, Pakistan (modified after Raza, 2007)

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Kashif Saeed, Kashif Yaqoob

ɨɨ Seismic Data Interpretation Seismic Interpretation means the conversion of seismic data into useful geologic information. The interpretation of reflection data requires the fitting of all geological and geophysical information into an integrated picture that is more complete and reliable than either source is likely to give alone. Ideally, this integration would be accomplished most efficiently if a single person highly competent both in geophysics and geology did it. However in actual practice such persons are very few and it is usually necessary for a geophysicist and geologist to collaborate at this stage of interpretation. The added information from the area like production analysis and driller’s observations are always helpful but for

the wild cats and early exploration stage of the field, such information is sparse and usually of less advantage. Geophysics is the investigation of subsurface using the laws and methods of physics and till date the seismic section is the most reliable picture of the subsurface. With the development of 3D seismic method, seismic cube is the latest approach and of the survey is done after time intervals to monitor the changes; resulting output is called 4D seismic. In seismic method measurement are made at the surface by using different geophysical instruments, which are then interpreted in terms of what might be in the subsurface. The behavior of different interfaces that give rise to reflection events is calculated from arrival times of seismic waves from these interfaces.

ʈʈ Fig. 4: Channels and younger sets of event shown on Seismic Line NP – 12

Integration of Geological, Geophysical, and Completion Data

Interpretation is the transformation of seismic reflected data into a structural picture by the application of corrections, migration and time depth conversion. Seismic reflection method uses sound waves to investigate the subsurface. The acoustic impedance governs the reflection, which is one of the rock properties and is given by the formula: Acoustic Impedance = Interval Velocity x Density Reflection arises at boundaries across which acoustic impedances changes. Greater the difference in the acoustic impedance across an interface, stronger will be the reflection generated. Seismic sections give us the detailed insight about the structure of the subsurface, where as for the stratigraphy, we need to integrate the seismic sections with well log data and completion profiles (if any), for through understanding of reservoir The main application of Structural analysis of seismic sections is in the search for hydrocarbon traps. Most structural interpretation use two way reflection time rather depth and time. Structural maps are constructed to display the geometry of selected reflected events. Discontinuous reflections clearly indicate parts and undulating reflections reveals folded beds. Similarly diffraction is indication of faults. In offshore Indus there are mostly growth faults. Mainly there are three types of features as identifies on the seismic data. 1. Channel System 2. Growth Faluting 3. Prograding Sequence Apart from these three main features another set of episode has been recognized in this work. This is the upward

stretch of the reflectors in very younger strata, shown in Fig. 4. In the Fig. the navy blue reflector (second from top) has been stretched upward from the middle of the section where as it separates apart with respect to the top most reflector as it moves towards its NE extreme. A rapid dumping of clastic sediments occurred particularly in the depression area during Neogene time. The Neogene strata during its deposition were occasionally subjected to erosion by the shifting channels (Fig. 4) of Proto-Indus River, which were subsequently filled by clastics during Middle to Late Miocene as well as during Pliocene.

ɨɨ Well Log Interpretation Interpretation of old well logs is a great learning experience and a challenge in the era when we have while drilling logging and measurements. The available log data was sorted and key wells were identified. 'A key well is one which has the max data and hence the interpreted parameters will have the least amount of uncertainty'. These wells will be used to estimate the relevant petro-physical parameters for the wells which are lacking key data. All the available logs were categorized to help implement a consistent system of interpretation that depends on the available suite of logs according to the following scheme: Type A: the key wells i.e. the most complete suite of logs (i.e. petro-graphic log, completed analyses from past engineers, a shallow reading log e.g. microlog and a deep reading log, GR, SP) and core data, production data, perforated intervals, RFT data and Well test data

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Kashif Saeed, Kashif Yaqoob

ʈʈ Fig. 4: Channels and younger sets of event shown on Seismic Line NP – 12

Integration of Geological, Geophysical, and Completion Data

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Kashif Saeed, Kashif Yaqoob

Integration of Geological, Geophysical, and Completion Data

tant for drilling fluids engineers to know the geothermal gradient in an area when they are designing a deep well. The down-hole temperature can be calculated by adding the surface temperature to the product of the depth and the geothermal gradient. As the geothermal analysis depend mainly on depth so in offshore Indus basin (table 1), the two main areas which need to be distinguished are: 1. Shelf Area 2. Basin Area

ʈʈ Fig. 5: The stratigraphic model of offshore and nearby onshore areas as derived from data of six wells, inter-well area has been filled by related seismic data.

Type B: same as Type A but no cores are available Type C: incomplete log suite e.g. no resistivity logs Type D: No available logs Apart from the individual well log interpretation, an attempt to correlate six wells was done. The stratigraphic and structural features of the basin have been linked to the adjacent onshore areas and to the tectonic evolution of the western margin of the Indian Plate. A detailed model of correlation of onshore

and nearby offshore region is displayed as Fig. 5.

ɨɨ Geothermal Analysis The geothermal gradient is the rate of increase in temperature per unit depth in the earth. Although the geothermal gradient varies from place to place, it averages 25 to 30°C/km [15°F/1000 ft]. Temperature gradients vary widely all over the surface and subsurface, sometimes increasing dramatically around volcanic areas. It is particularly impor-

Talking particularly of PakCan–01 well, the input parameters are depth, type of lithology, thickness, porosity, event type (deposition and erosion), time and base age, water depth, paleo-temperature and heat flow rates have been used for each lithological unit/layer. The porosity variations in depth play an important role in sediment compaction and decompaction in a basin. Last but not the least, the overlaying sediment load, water column, eustatic changes with time and tectonics have crucial impact over the sediments burial history. The data of PakCan–01 well has been used to precisely simulate deposition, fluid dynamics, and heat flow occurred during the process of subsidence, uplift

and erosion while various basin development stages. The results determine the potential volume and type of hydrocarbons generated in the basin and the period during which such hydrocarbon generation took place. The output data as a result of basin simulation comprises the generated hydrocarbon volume for individual layers encountered in the PakCan–01 well (Basin Area). In addition to the computed total matrix porosity, and computed subsidence, and type-II hydrocarbon histories have been generated. The hydrocarbon volumes generated for each layer in the well has been described in Table 2. ʈʈ Table 1: The description of PakCan – 01 well with respect to the geothermal analysis Location Spud Date Completion Date

Shelf Area 27 / 9 / 1985 05 / 05 / 1986

Total Depth (m)

3702

Formation at TD

Gaj

Age Comments

Status

Burdigalian Declared as non-commercial hydrocarbon discovery from lower Miocene Sandstone Plugged and Abandoned

ʈʈ Table 2: Output data report: Hydrocarbon volumes generated in each layer of PakCan–01 Layer Name

Thickness (m)

Lithology

M. Miocene

1250

Sandstone and Siltstone

L. Miocene

1307

Silty Shaly Sand

Pliocene Pleis. / Ho.

Total oil generated per km2/S.R. Thickness (mm tones)

Total gas generated per km2/S.R. Thickness (mm cubic meters)

8.152

199.490

10.171

19.478

840

Sandstone and Siltstone

0.037

0.000

1553

Sandstone and Siltstone

0.000

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Kashif Saeed, Kashif Yaqoob

Integration of Geological, Geophysical, and Completion Data

ʈʈ Fig. 5: The stratigraphic model of offshore and nearby onshore areas as derived from data of six wells, inter-well area has been filled by related seismic data.

and nearby offshore region is displayed as Fig. 5.

Shelf Area 27 / 9 / 1985 05 / 05 / 1986

Total Depth (m)

3702

Formation at TD

Gaj

Age Comments

Status

Burdigalian Declared as non-commercial hydrocarbon discovery from lower Miocene Sandstone Plugged and Abandoned

ʈʈ Table 2: Output data report: Hydrocarbon volumes generated in each layer of PakCan–01 Layer Name

Thickness (m)

Lithology

M. Miocene

1250

Sandstone and Siltstone

L. Miocene

1307

Silty Shaly Sand

Pliocene Pleis. / Ho.

Total oil generated per km2/S.R. Thickness (mm tones)

Total gas generated per km2/S.R. Thickness (mm cubic meters)

8.152

199.490

10.171

19.478

840

Sandstone and Siltstone

0.037

0.000

1553

Sandstone and Siltstone

0.000

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Kashif Saeed, Kashif Yaqoob

ɨɨ Well to Seismic Tie Well–Seismic Tie means to correlate data in order to formulate or verify an interpretation or to demonstrate the relationship between data sets acquired from seismic model and the associated well data model of the same area. Long, regional-scale 2D seismic lines are also tied to 3D surveys that cover a limited area, and 3D surveys of different vintages are tied to each other. Well logs are tied into seismic data routinely to determine the relationship between lithologic boundaries in the logs and seismic reflections. Properly tying all available data, including seismic data, well logs, check-shot surveys, synthetic seismograms and vertical seismic profiles, can reduce or, if there are sufficient data, eliminate ambiguity in interpretations.

Integration of Geological, Geophysical, and Completion Data

It is a comparison or the location of a comparison, of data. Properly processed and interpreted seismic lines can show good ties, or correlations, at intersection points. From Well Velocity Survey of PakCan–01, 117 points were selected on the curve to read the time from depth.

ɨɨ Integrated Evaluation and Results As Indus Offshore basin has been marked as marginal sag basin so it is expected that it could contain/provide major hydrocarbon plays when they are associated with appropriately buried basal fault blocks, and non-marine deposition of the basal interior fracture cycle, contemporaneous or younger salt dome uplift, growth faults, wrench fault-

ʈʈ Fig. 6: Two Way Time Vs. Depth Plot of Selected 117 points from well velocity survey

ʈʈ Fig. 6: The main structure drilled by PakCan–01 is indicated by red, SP 480 Seismic Line NP–12

ing, normal or gentle ocean-ward tilt of the basin, deltas and carbonate banks with reefal build-ups. The main structure on which the PakCan–1 well has been drilled is shown as Fig. 7. Stratigraphic analysis involves the subdivision of seismic sections into sequences of reflections that are interpreted as the seismic expression of genetically related sedimentary sequences. Unconformities can be mapped from the divergence pattern of reflections on a seismic section. The presence of unconformable contacts on a seismic section provides important information about the deposi-

tional and erosional history of the area and on the environment existing during the time, when the movements took place. The success of seismic reflection method in finding stratigraphic traps varies with the type of trap involved. Most such entrapment features are reefs, unconformity, disconformities, facies change, pinch-outs and other erosional truncations. After the detailed analysis from seismic data and correlation with Well Log data, the summarized stratigraphy of PakCan–01 well, at different depth intervals has been listed in table 3.

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Kashif Saeed, Kashif Yaqoob

Integration of Geological, Geophysical, and Completion Data

ʈʈ Fig. 6: Two Way Time Vs. Depth Plot of Selected 117 points from well velocity survey

ʈʈ Fig. 6: The main structure drilled by PakCan–01 is indicated by red, SP 480 Seismic Line NP–12

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Kashif Saeed, Kashif Yaqoob

Depth (m) 1112

Statigraphy Sea Floor – Holocene / Pliocene Marine Shales & Silts

1112 – 1454 Light Grey Shales & Siltstone with rare Sands 1454 – 1703 Near Shore Deltaic Sequence Fining Upwards 1703 – 1828 Marine Sequence regressing upwards to Fine Sand between 1703 and 1730 m 1828 – 2262 Deltaic Complex, mainly Bottom and Foreset Beds with major topset bars Sands between 1903 and 1863 m 2262 – 2710 Deepwater marine Shales with minor Siltstone, minor thin distal marine Sands between 2514 and 2616 m 2710 – 2908 Upward Fining deltaic Sequence with topset Sands between 2850 and 2908 m, grading upwards to thin forest 2908 – 2980 Deep water marine Shales and Siltstones. 2980 – 3118 Prodrading Deltaic Sequence below 3020 m. Regrading deeper water section between 2880 and 3020 m. 3118 – 3392 Deeper water marine Shales and Siltstones, Thin, Coarse grained, gas sands at 3313 – 3314 m. 3392 – 3398 Oxidized reddish brown iron rich Shales

Integration of Geological, Geophysical, and Completion Data

ɨɨ References 1. Abdul Waheed, 2003, Aspects of Petroleum Prospectivity of Tertiary Indus Delta: Pakistan’s untapped Exploration Frontier, AAPG International Conference, (Sep 21 – 24, 2003), Barcelona, Spain. 2. Baloch, S.M., and David G. Quirk, 1998, Seuence Stratigraphic and Structural Interpretation of the Offshore Indus Basin of Pakistan, American Association of Petroleum Geologists, Annual Conference Salt Lake City (May 1998 Abstract), Utah, U.S.A., p. 1–4. 3. Clift, P., and Molnar. P., 2003, Scientific Drilling of the Indian Ocean Submarine Fans, JOI/USSAC workshop for future IODP Drilling, 23 – 25th July 2003, University of Colorado, Boulder, CO, USA., p. 3. 4. Jaswal, T. M., and Maqsood, T., 2002, Structural Geometry of the Offshore Indus Basin, Pakistan, PAPG – SPE Annual Technical Conference and Oil Show (2–4 November, 2002), Islamabad, Pakistan.

3398 – 3700 Distal marine Shales and Siltstones with thin foreset beds at 3310, 3395, and 3525 m. ʈʈ Table 3: The detailed stratigraphy of PakCan – 01 well, at different depth intervals

ɨɨ Conclusions and Recommendations The present work is primarily based on interpretation of seismic data, its correlation with well data, well velocity survey, and completion data from PakCan–01 well in order to logically reason the failure of well, with a little glimpse on overall picture of Indus Offshore Basin, Pakistan. In the growing industry challenges from conventional to unconventional, it is the need of the hour to integrate all types of data available, especially in the basins with no significant discovery. The integration strategy should be applied to under-explored areas and basins with technical and drilling difficulties like Offshore Indus Basin, Pakistan to learn lessons from the miss hits and plan a foolproof strategy for future spuds in the area. The tectonics, stratigraphy, and hydrocarbon generation should be

studied in detail reaching the potential source, reservoir, and seal/cap rock determining the hydrocarbon potential of the area. A complete workflow prior to the initiation of study is relatively helpful, in order to integrate all the data available from all the sources and preferably, all the wells in the area. The vitrinite reflectance data, maturation history, basin analysis, and kerogen type studies should be done prior to static and dynamic model generation and incorporation of this information in the models is significantly important to portray the complete picture and developing the maximum trust on our models with minimum uncertainty. A detailed study on timing of developments of structures and maturation of source rock is strongly recommended for hydrocarbon hunt in Indus Offshore Basin, Pakistan.

ɨɨ Acknowledgements Authors thank DGPC-Ministry of Petroleum and Natural Resources for making available public data for study and LMKR for helping to reach and get the copies of data from repository.

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Kashif Saeed, Kashif Yaqoob

Depth (m) 1112

Statigraphy Sea Floor – Holocene / Pliocene Marine Shales & Silts

Integration of Geological, Geophysical, and Completion Data

3398 – 3700 Distal marine Shales and Siltstones with thin foreset beds at 3310, 3395, and 3525 m. ʈʈ Table 3: The detailed stratigraphy of PakCan – 01 well, at different depth intervals

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Papers

Intensification of high-viscosity oil production

Nazarii Hedzyk Intensification of high-viscosity oil production on the example of Yablunivske oil-and-gas-condensate field

The sample of oil from the well mouth number 96 of Yablunivske oil-and-gascondensate field was used for the tests (experiments). Depth of the well – 3600 m, initial formation pressure – 37 MPa, formation temperature – 92 °C. Composition of oil is as the following:

ɨɨ Introduction

densate field for measuring oil dynamic viscosity coefficient confirm all anticipation. There were also suggested technologies of using reagents for development high-viscosity oil fields. Heating the oil and adding the hydrocarbon solvent and other surfactant species into it allows us to reduce the coefficient of viscosity significantly and thereby increase the well productions, prevent complications during the process of its operation and intensify the process of developing heavy oil deposits.

Ukraine has favorable conditions for the forming of high-viscosity oil deposits. Such oil fields in the Western, Southern and Eastern regions occur in a wide stratigraphic range and are controlled by different types of traps. The use of the modern methods of exploration and development of such oil fields play an important role in building energy future. As you know the process of heavy oil production has some complications be-

6Abstract7

Ivano–Frankivsk National Technical University of Oil and Gas, Ukraine e–mail: nazarii.hedzyk@gmail.com Scientific supervisor: Oleksandr Kondrat

Nowadays we are faced with the problem of complete and profitable extraction of hydrocarbons from already explored oil and gas deposits. The influence of availability of the hydrocarbon solvent and/or the surfactant species helps us to reduce the oil dynamic viscosity coefficient and thereby increase the well production. Experiments with highviscosity oil with the example of Yablunivske oil-gas-con-

cause of physical and mechanical properties of oil: »» significant loss of pressure in the columns of pipes »» fast stopping of natural flowing »» heavy hydrocarbons pollution of bottomhole zone Methods for intensification of the highviscosity oil production can be divided into: »» Thermal methods »» Using of the hydrocarbon solvents »» Using of the surfactant species

»» »» »» »» »»

silica gel resin 25.5% by weight asphaltene 12.2% sulfur 1.39% bound water 9.9% small amount of paraffin 0.53%

ɨɨ Dependence of oil viscosity on availability of hydrocarbon condensate and surfactant species in the mixture The experiments were conducted with the help of the device 'r e o t e s t –2' and areometer in the temperature range of 25 to 80 °C (after each 5 °C) and volumetric condensate content in the system 0; 10; 20; 30; 40; 50; 60% with the density of 735 kg/m3. This device allows us to meas-

ure the coefficient of dynamic viscosity and other characteristics. Experiments show this dependence of oil density on temperature: ρo = −0,0029t2 − 0,3374t + 933,27kg/m3

Increasing of temperature from standard (20 °C) to formation (92 °C) involve decreasing of density from 925.36 to 877.68 kg/m3 (by 5.15%). The experiments results confirm the probability of the oil dynamic viscosity coefficient reducing due to the thermal influence and adding of hydrocarbon solvent. As a result of temperature increase from 25 to 80 °C the oil dynamic viscosity coefficient decreased from 874.07 to 30.04 mPa∙s (by more 29.1 times). At the temperature of 25 °C with increase in volumetric condensate content in the system from 0 to 60% vol. the oil dynamic viscosity coefficient decreased from 874.04 to 11.56 mPa∙s (by 75.61 times). 1 But the joint influence of both the temperature and the hydrocarbon solvent showed that with the increase in temperature from 25 to 80 °C and adding 60% of condensate into the system, the oil dynamic viscosity coefficient decreased from 874.07 to 4.96 mPa∙s (by 176.22 times). The experiments results were also used for calculating the optimum oil heating temperature above which the oil dynamic viscosity coefficient almost does not change. With the increase in the volumetric hydrocarbon condensate content from 0 to 60% vol. the optimum oil heating temperature decreases from 49.83 to 44.46 °C. According to the results of tests optimum oil heating temperature of oil equals 49.83 °C and reducing with in-

summer / 2 011

Papers

Intensification of high-viscosity oil production

Nazarii Hedzyk Intensification of high-viscosity oil production on the example of Yablunivske oil-and-gas-condensate field

ɨɨ Introduction

6Abstract7

Ivano–Frankivsk National Technical University of Oil and Gas, Ukraine e–mail: nazarii.hedzyk@gmail.com Scientific supervisor: Oleksandr Kondrat

»» »» »» »» »»

silica gel resin 25.5% by weight asphaltene 12.2% sulfur 1.39% bound water 9.9% small amount of paraffin 0.53%

ure the coefficient of dynamic viscosity and other characteristics. Experiments show this dependence of oil density on temperature: ρo = −0,0029t2 − 0,3374t + 933,27kg/m3

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Nazarii Hedzyk

ʈʈ Fig. 1: 1–0; 2–10; 3–15; 4–20; 5–25; 6–30; 7–40; 8–50; 9–60 % by weight Graphs of the dependence of the oil dynamic viscosity coefficient on the temperature for different volumetric condensate contents in the system.

ʈʈ Fig. 2: 1–25; 2–30; 3–35; 4–40; 5–45; 6–50; 7–55; 8–60; 9–65; 10–70; 11–75; 12–80 °C Graphs of the dependence of the oil dynamic viscosity coefficient on the different volumetric condensate contents in the system for temperature

Intensification of high-viscosity oil production

ʈʈ Fig. 3: Graph of the dependence of the absolute oil dynamic viscosity coefficient decrease on the temperature for the volumetric content in the system of the 20% hydrocarbons condensate

ʈʈ Fig. 4: Graph of the dependence of the absolute oil dynamic viscosity coefficient decrease on the volumetric condensate content in the system for temperature 45 °C

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Nazarii Hedzyk

Intensification of high-viscosity oil production

ʈʈ Fig. 3: Graph of the dependence of the absolute oil dynamic viscosity coefficient decrease on the temperature for the volumetric content in the system of the 20% hydrocarbons condensate

ʈʈ Fig. 4: Graph of the dependence of the absolute oil dynamic viscosity coefficient decrease on the volumetric condensate content in the system for temperature 45 °C

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Nazarii Hedzyk

creasing condensate content in the system: 10% vol. −49.43 °C, at 15% vol. −9.07 °C, at 20% vol. −48.35 °C,at 25% vol. −47.49 °C, at 30% vol. − 46.91 °C, at 40% vol. −45.67 °C, at 50% vol. −44.63 °C, at 60% vol. −44.62 °C. The optimum oil heating temperature for optimal hydrocarbon condensate content in the system 20% of vol.

(25% of vol. if considering oil) equals 48.35 °C. The oil dynamic viscosity coefficient equals 35.37 mPa∙s (24.46 times less than the value of the oil dynamic viscosity coefficient at the temperature of 25 °C and condensate absence) for these values of the volumetric condensate content in the system and oil heating temperature.

Intensification of high-viscosity oil production

ʈʈ Graphs of the dependence of the oil dynamic viscosity coefficient with the volumetric condensate content of 20% vol. on the temperature under different mass concentrations of the n i o g e n p –1000

ʈʈ Fig. 6: 1–0; 2–0.125; 3–0.25; 4–0.5; 5–0.75; 6–1; 7–2; 8–4; 9–6; 10–8 % wt

ɨɨ Dependence of oil viscosity from availability of hydrocarbon condensate and surfactant species in the mixture ʈʈ Graphs of the dependence of the oil dynamic viscosity coefficient with the volumetric condensate content of 20% vol. on the temperature under different mass concentrations of the r i p ox –6

The other method for intensification of heavy oil production is the joint use of the hydrocarbon solvents and the surfactant species. As reagents the surfactants r i p ox –6 and n i o g e n p –1000 were used. The mass concentration of surfactants in the mixture was 0.125; 0.25; 0.5; 1; 2; 4; 6; 8%. The results of these studies showed positive effect of adding the surfactant

№

ʈʈ Fig. 5: 1–0; 2–0.125; 3–0.25; 4–0.5; 5–0.75; 6–1; 7–2; 8–4; 9–6; 10–8 % wght

0.125

species for reduction in the number of times the dynamic viscosity coefficient of oil and to reduce the optimum temperature of oil heating. Therefore, for intensification of high viscosity oil production from wells of Yablunovske oil and gas field recommend append condensate into the well (r i p ox –6 or n i o g e n p –1000) with a mass concentration of 1%.

0.25

0.5

RIPOX–6

27.62

26.19

24.71

20.43

16.31

10.47

NIOGEN P–1000

16.11

15.4

14.95

14.16

13.69

12.6

ʈʈ Table 1 – Values of dynamic viscosity coefficient (mPa∙s) with condensate content of 20% at the temperature of 25 °C from different concentration of surfactant species

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Nazarii Hedzyk

Intensification of high-viscosity oil production

ʈʈ Fig. 6: 1–0; 2–0.125; 3–0.25; 4–0.5; 5–0.75; 6–1; 7–2; 8–4; 9–6; 10–8 % wt

№

ʈʈ Fig. 5: 1–0; 2–0.125; 3–0.25; 4–0.5; 5–0.75; 6–1; 7–2; 8–4; 9–6; 10–8 % wght

0.125

0.25

0.5

RIPOX–6

27.62

26.19

24.71

20.43

16.31

10.47

NIOGEN P–1000

16.11

15.4

14.95

14.16

13.69

12.6

ʈʈ Table 1 – Values of dynamic viscosity coefficient (mPa∙s) with condensate content of 20% at the temperature of 25 °C from different concentration of surfactant species

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Nazarii Hedzyk

Intensification of high-viscosity oil production

ɨɨ Technology of high viscosity oil producing

ʈʈ Fig. 7: 1–25; 2–30; 3–35; 4–40; 5–45; 6–50; 7–55; 8–60; 9–65; 10–70; 11–75; 12–80 °С Graphs of the dependence of the oil dynamic viscosity coefficient with the volumetric condensate content of 20% vol. on the mass concentrations of the r i p ox –6 under different temperature

Using the results of laboratory and analytical research developed the technology of exploitation of oil wells of Yablunovske deposit. In the initial period at high formation pressure, recommended to serve on the well annulus hydrocarbon solvent (condensate) with or without surfactant, which reduces the viscosity of oil. As the reduction of pressure in the development field and after stop of flowing recommend exploit well using gas-lift. To reduce the operating pressure and process costs, increase oil production gas should enter along the column of pipes. For gas-lift operation well 96 gas from high-pressure gas wells were used: from well 102 by gas-lift manifold and from well 87 – by pipeline. For preventing hydration in the gas-lift stream methanol was added.

Using results of experiments recommend well 96 exploration using gas-lift, with admission hydrocarbon condensate after each two days by 2–3 hours gas with pressure 10–12 MPa and flow 20 h.m3/d with adding hydrocarbon solvent in concentration 20% vol. and surfactant species (r i p ox –6) – 1–2% weight. In the final period of field in low reservoir pressure, recommended pumping exploitation of wells using rod pumps specially designed

ɨɨ Conclusions The oil heating and adding of the hydrocarbon condensate and other surfactant species into it allows us to reduce the coefficient of viscosity significantly and thereby increase the well productions, prevent complications during the process of their operation and intensify the process of developing heavy oil deposits. And results of well 96 exploitation suggest the possibility of practical use of technology gas-lift exploitation of oil wells. Literature references

ʈʈ Fig. 8: 1–25; 2–30; 3–35; 4–40; 5–45; 6–50; 7–55; 8–60; 9–65; 10–70; 11–75; 12–80 °C Graphs of the dependence of the oil dynamic viscosity coefficient with the volumetric condensate content of 20% vol. on the mass concentrations of the n i o g e n p –1000 under different temperature

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Nazarii Hedzyk

Intensification of high-viscosity oil production

ɨɨ Technology of high viscosity oil producing

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Papers

ɨɨ References 1. Boiko V.S. Development and exploitation of oil fields. - K.: ISDO, 1995. - 496 p.. 2. Handbook of Petroleum Engineering / By common. yet. Drs. Engineering. Science V.S. Boyko, R. M. Kondrat, R. S. Yaremiychuka. - K.: Lviv, 1996. - 620 p. 3. Petroleum equipment: Handbook / Ed. EI Buhalenko. - 2nd ed. - Moscow: Nedra, 1990. - 559 p.. 4. Handbook of oil production / under. Ed. Sh.K. Gimatudinova. -Moscow: Nedra, 1974. -704 Sec. 5. Theory and practice of gas lift / Yuri Zaitsev, R.A. Maksutov, O.V. Chubanov etc. Moscow: Nedra, 1987.-256 p. 6. Chekalyuk E.B. Thermodynamics of the oil reservoir. - Moscow: Nedra, 1965. – 240p. 7. www.halliburton.com

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Papers

visit us at

youngpetro.org

summer / 2 011

Papers

Tudor Florin Precup assoc. prof. Florinel Dinu PhD

SUPERSONIC

natural gas dehydration process compared to teg performance The water content of natural gas is an important parameter in the design of facilities for the production, transmission and processing of gas. In most countries this parameter is regulated in terms of dewpoint temperature (for example: −15°C in Romania),not the mass amount of water contained by the natural gas (for example: 0.112 g / ncm in the USA) although no one can control the temperature along transportation pipelines. In order to prevent all grievances which could be caused by wet natural gas, advanced dehydration systems are required. Among the most used are TEG based installations functioning on the absorption principle. But a direct cooling solution tries nowadays to enter the market and seems to offer some advantages that may push her to the top, at least in some favorable scenarios.

ɨɨ Natural gas humidity The natural gas humidity gives us the amount of water contained in the natural gas. For a sweet gas (like CH4) it is a decreasing function of the pressure and an increasing function of temperature. For acid gases (H2S and CO2), this is not

6Abstract7

ɨɨ Introduction Today’s unconventional gas challenges require unconventional solutions both in the upstream and downstream sector. Natural gases either from natural production or storage reservoirs contain water, which condenses and forms solid gas hydrates to block pipeline flow and especially affects metering and control systems. Natural gas in transit to market, should be dehydrated to a controlled water content also to minimize corrosion problems. There are three methods of dehydration: refrigeration, adsorption and absorption. Many of the classic dehydration systems use triethylene glycol (TEG), which is a hygroscopic liquid (has the ability to absorb water) for dewpointing. In this process TEG is placed into contact

SUPERSONIC natural gas dehydration process

the case. Acid gases exhibit a minimum in the water content. Sour gases (these are natural gases with an appreciable amount of acid gas) behave in an intermediate way. The humidity can be determined indirectly using correlations and charts or measured directly by dewpointmeters. One of the first methods used is the McKetta – Wehe chart (1958): The main chart is for a relatively low gravity gas. A smaller chart is provided to obtain a correction factor for higher gravity gas and a second correction factor is provided

with natural gas and strips the water out of the gas. Then it is heated to a high temperature and put through a condensing system, which removes the water as waste and reclaims the TEG for continuous reuse within the system. A new solution in terms of natural gas processing technology is the supersonic natural gas dehydration system which promises to offer a simple, safe, environmentally friendly, quick start up gas conditioning process which enables chemical free, high availability and unmanned operation. The temperature drop is achieved by transforming pressure to kinetic energy (i.e. supersonic velocity). This article aims to compare the performance (both technical and economic) of a classic TEG dehydration system and a possible supersonic solution for an extraction process at an existing underground natural gas storage (UNGS) facility (working gas volume: 1.25 blncm).

for the effect of brine versus pure water. If used correctly, errors of less than 5% can be obtained.

ɨɨ UNGS facility The Bilciuresti reservoir together with the surface equipment is the biggest UNGS facility in Romania. It is located about 40 km NNV away from the capital Bucharest and it has produced natural gas from 1962 to 1983 when it was transformed for storage. Here we present some general information about: 2000 m depth, 73 mD permeability, 25.5% porosity, 52°C temperature, 10.76 km2 area, 10–18 m thickness, 57 extraction wells and 1.25 blncm working gas volume. The geological formation in which the gas is injected is the Meotian. It is mainly used to cover the high gas demand during winter time. There are a number of 6 dehydration units based on the absorption process in TEG drying 12 mlncm of natural gas a day at 85–125 bar operating pressure. As a first step, we took a natural gas composition from a chromatograph analysis and calculated its humidity using a specific method: Natural gas composition: »» 0.9646 CH4 »» 0.0177 C2H6 »» 0.0059 C3H8 »» 0.0009 i-C4H10 »» 0.0012 n-C4H10 »» 0.0003 i-C5H12 »» 0.0003 n-C5H12 »» 0.0003 n-C6H14 »» 0.0001 n-C7H16 »» 0.0068 N2 »» 0.0001 O2 »» 0.0004 H2O »» 0.0014 CO2

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Papers

Tudor Florin Precup assoc. prof. Florinel Dinu PhD

SUPERSONIC

6Abstract7

SUPERSONIC natural gas dehydration process

for the effect of brine versus pure water. If used correctly, errors of less than 5% can be obtained.

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Tudor Florin Precup

SUPERSONIC natural gas dehydration process

FIG. 20-4 Water Content of Hydrocarbon Gas

ʈʈ Fig. 2: TEG dehydration system, source: KIMRAY University Presentations

The result was 0.558 g H2O / ncm natural gas. Further on, we conducted a study regarding the technical performance and economic efficiency of such a dehydration unit and the newest solution on the market based on natural gas expansion at supersonic velocities.

ɨɨ TEG dehydration

ʈʈ Fig. 1: McKetta – Wehe chart, source: gspa Engineering Data Book

Dehydration refers to the process of removal of particulate water from a produced gas stream. Triethylene glycol (C6H14O4) is a member of a homologous series of dihydroxy alcohols. It is a colorless, odorless and stable liquid with low viscosity and a high boiling point (288°C). It is a hygroscopic liquid, 100% soluble in water at 20°C and rich glycol (containing water) has a 92.8–99.7% regeneration rate in modern installations.

The process itself is very simple: the so called lean substance is brought into contact with the natural gas produced from the reservoir, during which it stripes the water out of the gas by absorbing it. Then it is heated above 100°C (boiling point for water) but not more than 288°C so that the water can evaporate and the glycol recycled. Such a unit is capable of 60°C dewpoint depression.

ɨɨ The TEG dehydration system The main components of such a TEG dehydration unit are: an inlet scrubber, the contact tower or absorber, a surge or storage tank, the reboiler with the water vapor vent, the glycol pump, and a three phase gas, glycol and condensate separator.

20-5

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Tudor Florin Precup

SUPERSONIC natural gas dehydration process

FIG. 20-4 Water Content of Hydrocarbon Gas

ʈʈ Fig. 2: TEG dehydration system, source: KIMRAY University Presentations

ɨɨ TEG dehydration

ʈʈ Fig. 1: McKetta – Wehe chart, source: gspa Engineering Data Book

20-5

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Tudor Florin Precup

The inlet scrubber is the first stage of liquid removal for the dehydration process. It eliminates free liquids from the gas stream and requires a liquid level controller and a high pressure dump valve. The absorber is the vessel where glycol and natural gas make contact in concurrent flow (gas flows up and glycol flows down). The inlet glycol temperature should be 12°C higher than the inlet gas temperature in order to avoid foaming or glycol loss. The storage tank holds the lean glycol before it goes to the glycol pump. It can be separate vessel or integral to the reboiler. The reboiler is the vessel where the rich glycol is heated and the water evaporates through the vapor vent. The pressure should be here at a minimum. The glycol pump circulates lean glycol to the absorber and rich glycol to the reboiler. It has a special design and is secured on a level surface.

SUPERSONIC natural gas dehydration process

The three phase gas/glycol/condensate separator is used to reclaim some of the gas that would ordinarily get lost through the still column and separates any liquids that might get carried over with the glycol such as condensate or compressor oils. Fixed parameters of a Dehy: »» Minimum and maximum gas capacity at a given pressure and temperature »» Gas composition »» Minimum and maximum heat input into the regenerator »» Fire tube surface area »» Vapor capacity of the still column »» Liquid and gas capacity of the inlet scrubber Variable parameters of a Dehy: »» Gas flow into the absorber »» Water content of the dehydrated gas »» Glycol circulation rate »» Glycol concentration

ʈʈ Fig. 3: Dutch supersonic dehydration device, source: TWISTER BV website

ʈʈ Fig. 4: Russian supersonic dehydration device, source: Oil and Gas Journal

ɨɨ The supersonic dehydration device The supersonic dehydration device is basically constructed of 4 parts: a vortex generator or swirling device, a supersonic (de Lawal) nozzle, a cyclone separator and a pressure recovery device (diffuser). Nowadays on the market there are two types of supersonic dehydration devices: a Dutch concept and a Russian one. The main difference is the swirling device which at the Dutch system is designed to be a long internal body. The swirling device (swirl valve or vortex generator) with it’s special design gives the natural gas a rotational motion which aims to be stronger and stronger. The main purpose is to sustain the coalescence of the liquid (water in the gas) and concentrate it at the walls. The supersonic nozzle allows the rotational flow to become supersonic. To

ʈʈ Fig. 5: Swirling device, source: TWISTER BV website

achieve that, the Mach number must be exactly 1 at the throat. This is the reason why this device allows very little turndown in the flowing parameters. A smaller Mach number means the nozzle is not working correctly and thus the natural gas speed will not exceed the sound barrier. A solution for that is to install more of those tubes designed with

ʈʈ Fig. 6: Supersonic nozzle, source: Wikipedia

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SUPERSONIC natural gas dehydration process

ʈʈ Fig. 3: Dutch supersonic dehydration device, source: TWISTER BV website

ʈʈ Fig. 4: Russian supersonic dehydration device, source: Oil and Gas Journal

ʈʈ Fig. 5: Swirling device, source: TWISTER BV website

ʈʈ Fig. 6: Supersonic nozzle, source: Wikipedia

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SUPERSONIC natural gas dehydration process

different nozzle geometries or, of course, to have a constant natural gas pressure. The third part is where the nucleation and droplet growth occur. Nucleation refers to a extremely localized budding of a distinct thermodynamic phase. There are basically two types of nucleation which are described by different theories: heterogeneous nucleation (occurs at nucleation sites or surfaces containing the liquid or vapor) and homogeneous nucleation (spontaneously and randomly but requires superheating or supercooling). The liquid formed here is also removed from the gas using a cyclonic co-axial separator. (see Fig.s 3 and 4). The last part of the device recovers the pressure lost, mainly in the supersonic nozzle. This is achieved by the help of shock waves, technology borrowed from the rocket industry. ʈʈ Fig. 7: Supersonic thermo-dynamics on analyzed natural gas

ʈʈ Fig. 8: Supersonic dehydration system, source: Gas Handbook 2004

ʈʈ Fig. 8: Supersonic dehydration system, source: Gas Handbook 2004Fig. 9: Liquid degassing vessel, source: TWISTER BV website 1 – air/seawater coolers 2 – upstream dehydration (for NGL extraction) 3 – gas/gas crossexchange 4 – inlet separator 5 – twister tubes 6 – liquid degassing vessel 7 – reinjection and/or disposal

ʈʈ Fig. 10: SUPERSONIC vs. TEG

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SUPERSONIC natural gas dehydration process

ʈʈ Fig. 8: Supersonic dehydration system, source: Gas Handbook 2004

ʈʈ Fig. 10: SUPERSONIC vs. TEG

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Tudor Florin Precup

SUPERSONIC natural gas dehydration process

ɨɨ Discussions

ɨɨ References

For the natural gas taken from our UNGS facility, we made a phase diagram using specialized computer software and we plotted above the supersonic thermo dynamics to see the dewpoint depression and pressure lost. It turns out that the device is not capable of such great depression like the absorption based system, but it is enough for Romanian regulations mentioned at the beginning of this article. As it is visible in the picture, the working parameters are crossing the hydrate boundary of the gas. But hydrates don’t form due to the very small time that the gas remains in the tube (2 milliseconds). Another fact is, that by increasing the number of supersonic devices, the system could dry more natural gas. Now the system is actually more complex, as it is shown in Fig. 7. The supersonic tubes are connected to a so called liquid degassing vessel which collects the liquid phase. Some glycol must be injected here in order to prevent hydrate forming so the device is actually not so chemical free as announced, but the volumes injected are much smaller that the ones used by the absorption system. The main economic parameters analyzed are presented in the charts below. There were done by using cost numbers given in the literature for both systems and the gas flow rates of the UNGS facility considered (Fig. 10). The technology can be also used for NGL recovery or hydrocarbon dewpointing and although it is used both onshore and offshore (on the Sarawak B11 platform in Malaysia), it has not been developed and tested subsea and is thus not proven for subsea applications. It is also stated that if it were to be applied

1. GSPA Engineering Data Book. 2. KIMRAY University Presentations – 'KIMRAY University Dehydration', September 26, 2006. 3. Schinkelshoek, P., Epsom, H., – 'Supersonic Gas Conditioning – Low Pressure Drop Twister for NGL Recovery', OTC–17884-MS-P, Twister B.V. 4. Karimi, A., Abdi, M.A. – 'Selective Removal of Water From Supercritical Natural Gas', SPE 100442, Memorial U. of Newfoundland. 5. Alfyorov, V., Bagirov, L., Dimitriev, L., Feygin, V., Salavat, I., Lacey, J.R. – 'Supersonic nozzle efficiently separates natural gas components', Oil and Gas Journal, May 23, 2005 6. Twister Supersonic Gas Solutions – 'How does Twister work?' 7. Twister Supersonic Gas Solutions – 'Twister SWIRL Valve' 8. Betting, M., Epsom, H. – 'Supersonic separator gains market acceptance', Twister BV, 9. World Oil, April 2007 10. Gas Processes Handbook 2004, Gulf Publishing Company. 11. http://en.wikipedia.org/wiki/Nucleation. 12. http://en.wikipedia.org/wiki/De_Laval_nozzle. 13. Streletzky, K.A., Zvinevich, Y., Wyslouzil, B.E., Strey, R. – 'Controlling nucleation and growth of nanodroplets in supersonic nozzles', Journal of Chemical Physics, volume 116, number 10 14. McCabe, A. – 'Design of a Supersonic Nozzle', The Mechanics of Fluids Department, University of Manchester, 1967 15. Nemec, T., Marsik, F. – 'Classical Nucleation Theory – Power Cycle Remarks', 14th International Conference on the Proprieties of Water and Steam in Kyoto 16. Luijten, C.C.M. – 'Nucleation and Droplet Growth at High Pressure', Technical University Eindhoven, 1998 17. van Wissen, R., Brouwers, J.J.H., Golombok, M. – 'In-line Centrifugal Separation of Dispersed Phases', Wiley InterScience, January 4, 2007 18. Peeters, P. – 'Nucleation and Condensation in Gas-Vapor Mixtures of Alkanes and Water', Technical University Eindhoven, 2002 19. Somnath Sinha, B.E. – 'Experimental and Modeling Study of Condensation in Supersonic Nozzles', Graduate Program in Chemical Engineering, Ohio State University, 2008 20. Kalikmanov, V., Betting, M., Bruining, J. – 'New developments in nucleation theory and their impact on natural gas separation', SPE–110736-PP, 2007 21. Gandhidasan, P. – 'Parametric Analysis of Natural Gas Dehydration by a Triethylene Glycol Solution', Mechanical Engineering Department, King Fahd University of Petroleum and Minerals, Dharan, Saudi Arabia, 2003 22. Bin Mohamad, A.S. – 'Natural Gas Dehydration Using Triethylene Glycol (TEG)', Faculty of Chemical & Natural Resources Engineering, University Malaysia Pahang, April 2009 23. Forster, R. – 'Practical Hints for Cost Effective Glycol Dehydration', Ruhrgas AG, Essen, Germany

ʈʈ Fig. 11: Twister tube, source: ANSYS website

remote from the wellhead the benefits would be lost. At last, we conclude that reduced footprint, utility requirement and manning requirements together with lifecycle cost reductions of about 40% speaks for this technology which, for our UNGS facility, would suite best, despite the high pressure drop (20%).

ɨɨ Abbreviations: TEG – triethylene glycol UNGS – underground natural gas storage blncm – billion cubic meters mlncm – million cubic meters ncm – normal cubic meter

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Tudor Florin Precup

SUPERSONIC natural gas dehydration process

ɨɨ Discussions

ɨɨ References

ʈʈ Fig. 11: Twister tube, source: ANSYS website

ɨɨ Abbreviations: TEG – triethylene glycol UNGS – underground natural gas storage blncm – billion cubic meters mlncm – million cubic meters ncm – normal cubic meter

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Tudor Florin Precup

24. Christensen, D.L. – 'Thermodynamic simulation of the water/glycol mixture', Aalborg University Esbjerg, February 2009 25. Sulaiman, M.H. – 'Gas Dehydration using Glycol Solution in Absorption and Adsorption Unit', University Malaysia Pahang 26. Mohamadbeigy, Kh. – 'Studying of the Effectiveness Parameters on Gas Dehydration Plant', Research Institute of Petroleum Industry Teheran, Iran, May 15, 2008 27. Erik, L., Tyvand, E., – 'Process Simulation of Glycol Regeneration', GPA Europe’s meeting in Bergen, 13th – 14th May 2002 28. Brathen, A., – 'Development of Processes for Natural Gas Drying', Norwegian University of Science and Technology, Department of Energy and Process Engineering, June 2008 29. Dengyu, J., Eri, Q., Wang, C., Liu, H., Yuan, Y. – 'A Fast and Efficiency Numerical Simulation Method for Supersonic Gas Processing', SPE 131239, 2010 30. Malyshkina, M.M. – 'The Structure of Gasdynamic Flow in a Supersonic Separator of Natural Gas', Telpofizika Vysokikh Temperatur, vol. 46, no. 1, 2008 31. Ijzermans, R.H.A – 'Dynamics of dispersed heavy particles in swirling flow', Thesis University of Twente, Enschede, 2007 32. Janssen, J.W.F., Betting, M. – 'Combined Test with the Improved Performance Twister Supersonic Separator and the Gasunie Cyclone Separator', 23rd World Gas Conference, Amsterdam 5 – 9 June 2006

Papers

Alexey A. Khrulenko Gubkin Russian State University of Oil and Gas

pproach for full field scale smart well modeling and optimization ɨɨ Introduction Smart (or intelligent) well is a well equipped with downhole sensors and downhole valves to control fluid inflows from the separated perforated intervals to the well, in real-time mode, without well interventions, to optimize production (Fig. 1). Till present about 800 wells have been equipped with smart completions around the world and the key motiva-

tions for it can be briefly comprised in the following points: »» Reduction of operational expenditures (OpEx) related to well interventions; »» Increasing oil production; »» Improving oil recovery; »» Mitigation of an impact that reservoir uncertainty could have on project performance. The following issues must be considered while screening possible smart well deployment: »» How to estimate the value added by smart completion? »» How to control smart well completions effectively? In recent years a lot of publications was dedicated to these tasks (for instance, [1–5]). Most of researchers used reservoir simulation as the main tool. Within their frameworks reservoir modʈʈ Fig. 1: Basic elements of smart well 1 2 3 4 5

– – – – –

Casing Tubing; Inflow control valves (i c v ) Isolation packer P/T gauges

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Papers

Alexey A. Khrulenko Gubkin Russian State University of Oil and Gas

– – – – –

Casing Tubing; Inflow control valves (i c v ) Isolation packer P/T gauges

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Tudor Florin Precup

pproach for full field scale smart well modeling and optimization

Realizations of porosity

#1.

#2.

ʈʈ Fig. 2: The illustration of the problem

els of real or generic fields were used as a tool for production optimization. This work adopts these approaches and, on the other hand, suggests the means of their implementation in scale of full field model.

ɨɨ The problem description Let’s consider a small offshore oil field that is planned to develop by three wells as subsea tie-back (Fig. 2). The whole produced wellstream shall be transported as a multiphase flow to a nearby producing platform on a larger field, since it requires wells to operate at high tubing head pressures. The smart completions are being considered as a means to maintain production and to avoid well interventions caused by increasing watercut,. It’s necessary to assess whether deployment of smart completions is a cost-effective solution. Although three exploration wells were drilled but still there is a strong degree of uncertainty in the reservoir

#3.

#4.

#5.

Realizations of permeability

properties description. A lot of simulation models can be built on the same set of initial data. Five realizations of porosity and permeability were chosen and considered to be sufficient to provide a representative vision of possible reservoir development scenarios (Fig. 3). The simulated field consists of two formations; each of them encloses the massive reservoir, fault-bounded in the east (Fig. 1). The upper formation is 40 m thick, the lower formation thickness is 45 m. Oil-water contacts of the upper and lower objective intervals occur at the depths 3300 and 3525 m with the initial reservoir pressure 330 and 352.5 bar, respectively. The model consists of 20 × 58 × 81 blocks with a typical size 100 × 100 х 1.25 m and with total number 54019 of active cells. Non-volatile black oil model was used with oil viscosity at the reservoir conditions equal to 0.55 c and water viscosity of 0.3 cP.

ʈʈ Fig. 3: Model realizations

Oil resources (s t o o i p , or Stock Tank Oil Originally In Place) for various model realizations were kept approximately at the following levels: »» for the upper reservoir: 10.65 mln m3 »» for the lower reservoir: 26.1 mln m3 It is planned to develop the field using three wells; each of them drains the upper reservoir through deviated interval, and the lower reservoir – through the horizontal interval. Three perforation intervals were specified for each well: one in the upper formation and two (approximately equal in length) – in the lower formation. In case of smart completion these intervals are controlled independently by i c v s each of them can be set in 10 possible positions ('shut', 8 intermediate, 'fully open').

The following system of parameters, controlling the wells operation, was set (in the order of significance): »» Liquid rate of 1650 m³/d for all wells; »» Minimum tubing head pressure (THP): 40 bar; »» Minimum bottomhole pressure was limited by the oil bubblepoint pressure (245 bars).

ɨɨ Framework for modeling and optimization Two main types of optimization strategies are currently in use, namely, proactive and reactive. Reactive optimization strategy is aimed at improving instant production performance (increasing well oil rates, reduction in water and gas production, etc.) by means of a certain

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Tudor Florin Precup

pproach for full field scale smart well modeling and optimization

Realizations of porosity

#1.

#2.

ʈʈ Fig. 2: The illustration of the problem

#3.

#4.

#5.

Realizations of permeability

ʈʈ Fig. 3: Model realizations

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Tudor Florin Precup

pproach for full field scale smart well modeling and optimization

Full field model Full field run over the current time step Flux-file

optimization routine (or a rule) that utilizes data of well zone tests, carried out earlier, to determine the best combination of i c v settings. On the other hand, proactive strategies use reservoir models, enabling to predict reservoir performances over a certain time horizon (or optimization step). Thus, the reservoir model serves as 'crystal ball' that helps to determine the i c v settings delivering the maximum of the target function (it can be, say, oil production) in the future. Reactive strategies (refer, for instance, [1, 5]) can easier be implemented in a real oil field than proactive ones. However, proactive strategies can be much more rewarding. Both strategies can be used in reservoir models. In this work the proactive optimization strategy was implemented in the following manner: »» Time of prediction was divided into a number of optimization steps; »» The commercial reservoir simulator (Eclipse) was coupled with Matlabbased program add-in enabling to control the i c v settings; »» Over every optimization step the controller performs multiple runs of a model to determine a combi-

nation of i c v settings that delivers the maximum of a target function by means of Direct Search [4] method. Cumulative oil well oil production was used as the target function. Previously this type of model-based optimization strategies (proactive strategies) was presented in several publications (refer, for instance, [2–4]) and showed good results. We do believe that it is difficult and inefficient to implement the aforementioned approaches in full field reservoir models directly, because it would end up in large, multidimensional and timeconsuming optimization problem. The essence of the proposed approach is to divide the initial model into a few small ones. Thus, these small models, having smaller dimensions than initial one, can be easily optimized separately by means of the above-described approach. It’s necessary to note that this optimization strategy can be easily converted (?) to reactive one by performing the optimization over a short time horizon that may not cover entire period between two decision points. In point of fact, sector models turn to well models. Three sector models were defined near each well. The eliminated part of

Sector model #1

Sector model #2

Sector model #3

New flux-file, optimized valve settings (as initial guess)

Well settings optimization

Optimized valve settings

optimization step

Sector model generation

ʈʈ Fig. 4: The initial reservoir model and defined sectors around wells

Full field model run

Do results of sector models have a good match with full field one?

Yes Next step ʈʈ Fig. 5: Scheme of the optimization routine

the reservoir was taken into account by means of the Flux Option [6]. This option enables simulator to produce the flux-file containing boundary conditions for sector models. Then the flux-file can be used for reduced runs. When sector models are optimized, it is necessary to check if the solution ob-

tained for them has a good match with the solution for full field one (Fig. 5). In this work the discrepancies of well oil rates and oil production were used as the fitting criteria. In case of a poor matching (discrepancy of more than 1% for either parameter) the outer cycle of optimization is repeated.

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Tudor Florin Precup

pproach for full field scale smart well modeling and optimization

Full field model Full field run over the current time step Flux-file

Sector model #1

Sector model #2

Sector model #3

New flux-file, optimized valve settings (as initial guess)

Well settings optimization

Optimized valve settings

optimization step

Sector model generation

ʈʈ Fig. 4: The initial reservoir model and defined sectors around wells

Full field model run

Do results of sector models have a good match with full field one?

Yes Next step ʈʈ Fig. 5: Scheme of the optimization routine

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Tudor Florin Precup

pproach for full field scale smart well modeling and optimization

ʈʈ Fig. 8: Economical analysis of smart well deployment ʈʈ Fig. 6: FOPTs and incremental oil production due to smart completion

ɨɨ Results of numerical experiments The five models corresponding to the different porosity-permeability realizations were built and optimized. In addition, five base cases without smart completion were evaluated for comparison purposes. Field Oil Production Totals (fo p t ) and incremental produced oil (the difference between fo p t for optimized and base cases) are shown on the plot below (Fig. 6). Fig. 7 gives an example of valve positions changing through the time of simulation.

ʈʈ Fig. 7: The changing of i c v s during simulation

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Tudor Florin Precup

pproach for full field scale smart well modeling and optimization

ʈʈ Fig. 8: Economical analysis of smart well deployment ʈʈ Fig. 6: FOPTs and incremental oil production due to smart completion

ʈʈ Fig. 7: The changing of i c v s during simulation

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Tudor Florin Precup

ɨɨ How to assess the effect in terms of NPV?

t 0

Eff  NPV * − NPV  ∑ ( Rt* − Et* ) ⋅ α t − ∑ ( Rt − Et ) ⋅ α t  ∑ ( Rt* − Rt − Et*  Et ) ⋅ α t ;

(1)

where: Rt – revenues, received during the t-th time step (usually equals to 1 year); Et – operational and capital costs of the well construction and operation during the t-th time stept; T – planning period; i – discount rate (fractions of unit); αi – discount factor If at the time of commissioning the difference between capital investments into conventional and smart well completions is known and is equal to , and operational costs are equal to , then the equation (3) can be re-written in the form: T

t 0

Eff  ∑ ( Rt − Rt* ) ⋅ α t − ( E0* − E0 ) ⋅ α 0  ∑ ( Rt − Rt* ) ⋅ α t − ∆E0 ;

(2)

Finally, equation can be written in the form: T

Eff  ∑ (Qt* − Qt ) ⋅ α t p − ∆E0 ;

ɨɨ Brief conclusions

When production profiles both for conventional and 'smart' case are obtained, it’s possible to make an economic analysis of i c v deployment. Since we compare smart vs conventional well completions, it’s possible to express the economic effect as the difference between n pv of the smart ('*') and base cases: T

pproach for full field scale smart well modeling and optimization

(3)

t 0

The result for case #5 you can see at the Fig. 8. Given oil price p is 50 $/bbl, discount rate i is 12%, an additional cost of smart completion ΔE0 is 2 mln $ per well (for instance, cost of smart well completion for Shell’s smart wells in Brunei were about US$ 1.8 mln per well [7]). It can be seen that finally smart completions brought the tangible benefits and their repayment period turned out to be relatively short (5 years). However, the reservoir conditions and very harsh operational constraints can be considered as very favorable to deploy smart completions.

»» The proposed approach allows to estimate the amount of incremental oil that could be produced by using the smart well technology. Though in the real reservoir engineering practice model ability to correctly predict reservoir behavior is often a matter of dispute (or belief ), it is feasible to get model providing reliable short-time production forecast and use this model to optimize production profile. »» The proposed approach showed good computational performances. 1–2 external iterations were required for most of optimization steps to converge. »» Though Direct Search method turned out to be effective it does

not guarantee that the global optimum is found. »» Smart wells were capable to mitigate the impact of geological uncertainty on the project performances. The overall effect (both n pv and incremental oil) was always positive, but not for all wells. In every case there were at least one or more smart wells that produced less oil than conventional ‘dumb’ ones. »» Issues of reliability and possible production losses caused by valve failures were not discussed in this study, although we should point out that it is very important issue.

ɨɨ Bibliography 1. Naus M.M.J.J., Dolle N., Jansen J.-D., Optimization of Commingled Production Using Infinitely Variable Inflow Control Valves, SPE Production & Operations, Volume 21, Number 2, pp. 293–301, 2006. 2. Yeten B., Brouwer D.R., Durlofsky L.J., Aziz K., Decision analysis under uncertainty for smart well deployment, Journal of Petroleum Science and Engineering 43, pp. 183–199, 2004. 3. Meum P., Tøndel P., Godhavn J-M., Aamo O.M., Optimization of Smart Well Production through Nonlinear Model Predictive Control, SPE 112100, 2008 4. Emerick A.A., Portella R.C.M, Production Optimization With Intelligent Wells, SPE 107261, 2007. 5. Grebenkin I.M., Davis D.R., Analysis of the Impact of an Intelligent Well Completion on the Oil Production Uncertainty, SPE 136335, 2010. 6. Eclipse Reference Manual, Schlumberger, 2008. 7. Obendrauf W., Schrader K., Al-Farsi N., White A., Smart Snake Wells in Champion West – Expected and Unexpected Benefits From Smart Completions, SPE 100880, 2006.

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Tudor Florin Precup

ɨɨ How to assess the effect in terms of NPV?

t 0

Eff  NPV * − NPV  ∑ ( Rt* − Et* ) ⋅ α t − ∑ ( Rt − Et ) ⋅ α t  ∑ ( Rt* − Rt − Et*  Et ) ⋅ α t ;

(1)

t 0

Eff  ∑ ( Rt − Rt* ) ⋅ α t − ( E0* − E0 ) ⋅ α 0  ∑ ( Rt − Rt* ) ⋅ α t − ∆E0 ;

(2)

Finally, equation can be written in the form: T

Eff  ∑ (Qt* − Qt ) ⋅ α t p − ∆E0 ;

ɨɨ Brief conclusions

pproach for full field scale smart well modeling and optimization

(3)

t 0

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Papers

Dawid Wojaczek Supervisor: Aleksandra Jamrozik, PhD

Zeolites

as natural sorbent in removing pollutants from the drilling waste Used drilling muds are heterogeneous, hazardous waste which contains significant percentages of water – soluble salts, heavy metals. Mainly, pollutions of used drilling muds are caused by: »» biocides, »» oil, »» completion or stimulation of fluid components, »» corrosion inhibitors, »» reservoir fluids (crude oil, brine), »» drilling mud’s chemical components. Drilling muds and cuttings are the biggest part of waste created during drilling processes. Nowadays, we can observe three trends in management of drilling waste: Minimization of waste quantity can be made by using drilling muds and additives which are less environmentally hazardous and by drillings which generate minimal waste quantity (e.g. directional drillings, with smaller diameter and with use of smaller amount of drilling mud). Drilling waste can be stored in special location (pits, mud boxes), inject-

6Abstract7

ɨɨ Introduction

The purpose of laboratory investigation was to estimate the influence of zeolites’ sorbent on used drilling mud. Usefulness of zeolites’ sorbent in removing process was trialed. Zeolites are used for removal of organic matter, heavy metals and pollutants from the drilling waste due to their adsorption and ion exchange capacity.

ed to salt caverns or absorbed stratums. [1] Methods of disposal drilling waste divide to: »» Physical – mechanical methods, thermal methods, flocculation; »» Chemical – water wash, silicon dioxide emulsification and stabilization; »» Biological – landfarming, composting, bio-reactivation, vermiculture; »» Recycling – usage to cement production, concentrate blocks, stabilization of grounds, renovation of bogs, road surface.

Zeolites as natural sorbent in removing pollutants

To put into use drilling waste it is necessary to ensure their non-toxic empirical formula. [2] Zeolites are crystalline, highly porous materials which belong to the class of aluminosilicates. Crystals of zeolite are characterized by a three – dimensional pore system. [3] Zeolites create various structures, such as zeolites A (Fig. 1) and X (Fig. 2). They are used as absorbent in many fields, for example nuclear and petrochemical industry, medicine and domestic pet care. In experimental works there were examined empirical formula of mud, particularly contents of toxic chemical substance, after and before adding zeolites’ sorbent. In research, model and used drilling muds different in contents were examined. In this study were used chromatography and UV-VIS spectrophotometry methods to describe the results of the efficiency of sorption of toxic substance from the drilling waste.

Composition of examined zeolites is shown in Table 1.

ʈʈ Fig. 1. Zeolite type A

ʈʈ Fig. 2. Zeolite type X

ɨɨ Research In this investigation model potassium – polymer and used potassium – chloride drilling muds were compared. Compositions of each drilling muds are shown in Table 2 and Table 3. component

concentration

Bentonite

3.00%

CMC LV 1.60% PHPA

0.40%

Biopolymer

0.60%

KCl

8.00%

NaCl 15.00% Shale inhibitor 3.00% Lubricant 1.20% ʈʈ Table 2. Model potassium – polymer drilling mud component KCl

concentration 3.00%

CMC LV 2.50% component

concentration

SiO2 65 – 71.3 % Al2O2 11.5 – 13.1%

Polysaccharide

0.25%

PHPA

0.10%

K2CO3

0.05%

KOH

0.25%

CaO

2.7 – 5.2 %

Corrosion inhibitor

0.10%

K2O

2.2 – 3.4 %

Biodegradation preventing agent

0.30%

Fe2O3

0.7 – 1.9 %

Detergent

0.50%

MgO

0.6 – 1.2 %

Na2O

0.2 – 1.3 %

Non-organic blocker

0.70%

TiO2

0.1 – 0.3 %

Baryte

0.40%

ʈʈ Table 1. Composition of zeolites

Organic blocker 7.00%

ʈʈ Table 3. Used potassium – chloride drilling mud

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Papers

Dawid Wojaczek Supervisor: Aleksandra Jamrozik, PhD

Zeolites

6Abstract7

ɨɨ Introduction

Zeolites as natural sorbent in removing pollutants

Composition of examined zeolites is shown in Table 1.

ʈʈ Fig. 1. Zeolite type A

ʈʈ Fig. 2. Zeolite type X

concentration

Bentonite

3.00%

CMC LV 1.60% PHPA

0.40%

Biopolymer

0.60%

KCl

8.00%

NaCl 15.00% Shale inhibitor 3.00% Lubricant 1.20% ʈʈ Table 2. Model potassium – polymer drilling mud component KCl

concentration 3.00%

CMC LV 2.50% component

concentration

SiO2 65 – 71.3 % Al2O2 11.5 – 13.1%

Polysaccharide

0.25%

PHPA

0.10%

K2CO3

0.05%

KOH

0.25%

CaO

2.7 – 5.2 %

Corrosion inhibitor

0.10%

K2O

2.2 – 3.4 %

Biodegradation preventing agent

0.30%

Fe2O3

0.7 – 1.9 %

Detergent

0.50%

MgO

0.6 – 1.2 %

Na2O

0.2 – 1.3 %

Non-organic blocker

0.70%

TiO2

0.1 – 0.3 %

Baryte

0.40%

ʈʈ Table 1. Composition of zeolites

Organic blocker 7.00%

ʈʈ Table 3. Used potassium – chloride drilling mud

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Dawid Wojaczek

ɨɨ Samples preparation

ɨɨ Contents of pollutants in drilling waste Changes of ions’ contents in drilling muds are shown in Table 4. For all samples using of zeolites decreases contents of potassium, chloride and sulfate. Contents of calcium and magnesium increase.

ɨɨ Spectrophotometry results

ɨɨ Research methodology Empirical formula of samples was performed using Optima 7000 DV Instruments. Two concentrations of filtrate (1 and 10 %) were examined. For small concentrations of element the result of test for greater contents is important. Analogically, for greater concentration of element the result of test for smaller contents is correct. Adopted method allows appointing 41 different chemical elements in composition of drilling waste. Contest of chloride in drilling waste was examined with titration method. Spectrophotometry set-up consisted of U–1900 Hitachi spectrophotometer and PC with UV solution software. Samples were put in glass cuvettes and tested in wavelength scan measure type. Starting wavelength was 500 nm, ending wave-

Cl- [mg/l]

length was 190 nm and scan speed was 400 nm per minute.

In this laboratory investigation 4 samples were prepared. Drilling muds with zeolites were mixed achieving concentration of zeolites 20%. Afterwards all samples were shaken for 24 hours to provide better ions’ exchange. Finally fluids were pressed by filtrate-press. Some filtrates were sip in funnel one more time to ensure sufficient cleanliness of samples for spectrophotometry. Samples prepared this way were examined.

chemical element

Zeolites as natural sorbent in removing pollutants

ʈʈ Fig. 3: Absorbance of model potassium – polymer drilling mud

Results of UV-Vis spectrophotometry examination are shown in Fig. 3 and Fig. 4. As we can see absorbance of each sample decrease.

ɨɨ Conclusions 1. Zeolites decrease contents of pollutants from drilling mud. 2. 20% contents of zeolites is not enough to decrease all pollutants substandard. 3. Using zeolites decrease absorbance in all examined samples. 4. Increasing contents of Ca2+ and Mg2+ is not dangerous to environment in compliance with EU law. ʈʈ Fig. 4: Absorbance of used potassium – chloride drilling mud

used potassium – chloride

ɨɨ References

model potassium – polymer

23086.46

22373.91

120918.89

116999.89

Ca2+ [mg/l]

138.95

2072.95

8.97

69.06

K+ [mg/l]

14102.97

9078.66

4012.69

3729.38

Mg2+ [mg/l]

22.46

74.53

0.31

0.44

Na+ [mg/l]

8318.01

8857.22

5799.00

5830.55

SO42- [mg/l]

881.7

802.47

28.19

19.26

ʈʈ Table 4. Contents of pollutants in drilling muds

1. A. Jamrozik, Możliwość kompleksowego recycling odpadowych płuczek wiertniczych, Wydawnictwa AGH, Kraków 2009 2. Z. Halat, J. Hycnar, Properties and utilization of drilling waste, Gospodarka surowcami mineralnymi, t. 24, 2008 3. http://www.bza.org/zeolites.html (2011–05–05) 4. A. Jamrozik, A. Gonet, S. Stryczek, D. Wojaczek, Ł. Maciołek, Aktywność sorbentów klinoptylolitowych w środowisku odpadowych płuczek wiertniczych, Wiertnictwo, Nafta, Gaz 2011

summer / 2 011

Dawid Wojaczek

ɨɨ Samples preparation

ɨɨ Spectrophotometry results

Cl- [mg/l]

length was 190 nm and scan speed was 400 nm per minute.

chemical element

Zeolites as natural sorbent in removing pollutants

ʈʈ Fig. 3: Absorbance of model potassium – polymer drilling mud

Results of UV-Vis spectrophotometry examination are shown in Fig. 3 and Fig. 4. As we can see absorbance of each sample decrease.

used potassium – chloride

ɨɨ References

model potassium – polymer

23086.46

22373.91

120918.89

116999.89

Ca2+ [mg/l]

138.95

2072.95

8.97

69.06

K+ [mg/l]

14102.97

9078.66

4012.69

3729.38

Mg2+ [mg/l]

22.46

74.53

0.31

0.44

Na+ [mg/l]

8318.01

8857.22

5799.00

5830.55

SO42- [mg/l]

881.7

802.47

28.19

19.26

ʈʈ Table 4. Contents of pollutants in drilling muds

summer / 2 011

Working for an operator

The work and life on a drilling rig is definitely something that you will not experience anywhere else.

Working for an operator

I have joined Maersk Oil and the MITAS programme just after graduating from AGH University of Science and Technology, Faculty of Drilling, Oil and Gas, in August 2009. I am a MSc. Drilling Engineer by education but also an engineer at heart. First time I have heard about Maersk Oil was during a presentation that the company gave at my university in 2008. Before that the ‘white star on the blue square’ logo was in my mind strictly tied to the container shipping business. I did not realise that there is an oil part to it, nor that Denmark is an oil producing country covering it’s own consumption and even exporting hydrocarbons. As you can see now, I work under the white star logo, a clear success of the advertising campaign. At the moment three more graduates from my faculty work in Maersk Oil, with one more coming this summer to join the m i t a s ranks. m i t a s – Maersk International Technical and Science programme – is the graduate entry level programme bringing recent university graduates to work in the energy sector of the a p m m Group. That is, not only in Maersk Oil, but in Maersk Drilling and f p s o s as well.

Jędrzej Bryła

Currently, there are 68 graduates from 23 countries enrolled in m i t a s . Maersk Oil is an upstream operator and explorer of the fields in the Danish and UK North Sea, offshore Qatar, in Kazakhstan, Brazil, Angola and Norway, and soon in the Gulf of Mexico. Through the growing portfolio of operations numerous opportunities arise for young engineers like me. I started my adventure with the Drilling Department in Copenhagen, within the Danish Underground Consortium (DUC), which is a joint venture between Maersk Oil, the operator, Chevron and Shell. I have been employed as a Well Site Engineer (WSE), which is somewhat a drilling engineer who is working mostly offshore. My schedule was 2 weeks on the rig, 2 weeks in the office, 2 weeks on the rig again, and 2 weeks off. It might sound like a lot of work, and actually it is, but it carries an invaluable steep learning curve. Especially when being on the spot where the action occurs – on an offshore drilling rig. I have then, after 8 months, transferred to work as a WSE in Doha, Qatar. 'Rotating' to other locations and business units is one of the ideas behind the MITAS programme.

But first things first! Before you go offshore you have to pass a… survival course. No, it is not the one where you go to the woods and eat roots or hunt for rabbits. This is a course that teaches you how to deal with almost any emergency that might happen while offshore, from first aid training and fire fighting to… escaping from a crashing helicopter while being submersed in freezing water – upside down! As scary it may sound, it is pretty much good fun, but more importantly, it’s better to experience this in a controlled environment with divers by your side, than having first contact with such an event in a real life situation. The work and life on a drilling rig is definitely something that you will not experience anywhere else. I am deliberately using the word 'life', as obviously you cannot go home every night, and you cannot work 24 hours a day, some time is left for you to try to enjoy life while being there. But I will come back to that later. While thinking about the work offshore one thing pops up into my mind – it is all about making sure, and then making sure that you are actually sure. Any kind of mistakes, especially the ones that in hindsight could have been avoided, are very costly. Let me stress it here – monetary value is one thing, but doing something the wrong way on a drilling rig can seriously injure or kill you or your colleagues. There is not enough ink in the world to describe how important is safety awareness in that kind of environment. All in all, it is a kind of mine/factory type of place in a very remote loca-

tion. Having said that, if you follow the rules and procedures, you are as safe as you would be working in the office. My day to day tasks on the rig involved mostly reporting and supporting the Company Man (a fellow representative of Maersk, the company which is paying the bills, so to say) with any kind of engineering or operational work. Most importantly, the overall goal of this assignment, in the long run, is to learn and experience as much as possible about the drilling operations. Until I had gone to the rig, I did not realise the degree that the execution limitations of a project define the initial engineering and planning parts. Obviously you cannot go home every night, and you cannot work 24 hours a day, some time is left for you to try to enjoy life while being there. The weather – a subject you talk about when you actually run out of things to talk about. Well, not when offshore! I have experienced two extremes during my 'rotations' in Denmark and Qatar – winter in the North Sea and summer in the Middle East. From −20° C, taking into account the 70 knot winds making a chill factor of −50° C, to +50° C offshore Doha. The locations of the business units influence the whole experience as well. Copenhagen, a picturesque capital of Denmark, offers a feeling of tranquillity. As I am still to experience, it is said to be amazing during summer, with the long days to be spent beside the Nyhavn canal and with weekends on the beach. Doha in turn offers a bundled experience of the traditional Arab world with a mix of, mostly hotel based, 'high life'. Trips to the desert using all kinds of vehi-

summer / 2 011

Working for an operator

The work and life on a drilling rig is definitely something that you will not experience anywhere else.

Working for an operator

Jędrzej Bryła

summer / 2 011

cles are also a popular way of spending free time. Doha as well serves as a very good departure point for trips to Asia or for a weekend in Dubai or Oman. Working for an operator brings a lot of technical and non technical experiences together. Through the various operations, assignments and projects one is exposed to different technologies and a range of applications. It gives a broader view on the industry, and business as a whole, than a strictly technically focused career with a service company. Apart from the owner, an operator has the biggest stake in the asset that is being developed – the oil/ gas field. We have the licence to operate hence the optimum development of a reservoir lies in our interest. This in turn necessitates the work of the brightest people and cutting edge technologies (to be fair, the technology is often supplied by the various service companies);

Jędrzej Bryła

especially in Maersk Oil’s case which deals with mostly tight and difficult to produce reservoirs. Depending on the production sharing agreement with the owner, an operator is the end-party that owns the produced oil. A service company in turn is focused mostly on selling the service, independent of the final production. Of course, the more successful the product is (that will eventually lead to an increase in production), the more it will be bought and applied. Taking the m i t a s programme as an example, it is clear, that a great emphasis is put on versatility of skills gained through the different positions and projects. I can only recommend an 'operating' career as a true way to get the most exposure and insight into the oil business and the entire world energy sector.

Young Proffesionals

The Fire Within Jakub Slek

SPE Poland Young Professionals Founding Committee

One of those warm mornings in the middle of April, chestnut trees had just started to blossom – it meant that the time of high school final exams or 'Tests of maturity' was approaching. Once faded memories of me seven years ago became little by little more vivid and clear. I almost felt the stress before the final exams and the university entry exams. I summoned back images from five years of hard working, studying, but also partying and having good time with newly met people, who later became my friends. I brought back the feeling of 'job-well-done', as our team gathered altogether to work for the sake of SPE and the student’s community. Internship, master’s degree exam, first serious job and… wait! Is that it? s p e Student Chapter forged friendships that have lasted against all odds, despite the fact that we have scattered across Europe and beyond. The deposits of positive energy which drove us during the five years of studying and working, seem to be inexhaustible. We can see the same fire within students right now and I truly believe that 'East meets West' Conference is the best example of what Polish students are capable of.

We have decided to establish s p e Poland Young Professionals committee to help students keep this fire burning within them and advise them on how to channel this positive energy. Young Professionals combines (organization, so singular, like u s a ) the rookie’s enthusiasm, passion and a bit of naivety with the aspiration to gain full professional experience. s p e is an association that does not recognize corporate, political or national banners, in a way – it 'stands above differences' and therefore provides the best plane for building a structure of assistance and mutual support, but most importantly of trust and friendship. We are the first generation of Poles who barely remember or do not remember times of People’s Republic of Poland at all. We do not carry the burden of communism and even as teenagers we were able to start doing our part in building a modern society of educated citizens and not a of mindless mob. The sooner one begins, the better. The period of academic education is the best time to start releasing the positive energy that comes from the fire within us. That’s what we did and that’s what we shall continue to do through SPE Poland

summer / 2 011

Jędrzej Bryła

Young Proffesionals

The Fire Within Jakub Slek

SPE Poland Young Professionals Founding Committee

summer / 2 011

Young Professionals committee. 'Academic' period of our lives was just the beginning. We have just begun our adventure. Our ideas of how s p e y p shall look like, time shall shape. We can declare with confidence though, as we are gaining our professional experience in different regions of the globe, that the main our activities will be performed through internet. Website with articles, blogs, picture galleries, our achievements and thoughts we want to share, as well as webinars, 'Ask a Young Professional' option and so on. Live meetings are also considered. Lectures, workshops – these

Jakub Slek

are the kind of activities that you can expect us to perform. As students our parents fought for free Poland with strikes, marches, underground newspapers and self-education. We did not have to, but as SPE YP, we want the next generation of students to realize that through sharing knowledge and experience, learning mutual trust and respect, through becoming self-aware citizens, we can do our part in making Poland, Europe and the World a better place. Sounds pompously? Sure, it does, but every home is built of smaller components. And every home needs its 'Vestal Virgin' to keep the household’s fire burning.

Conference

Student International Scientific

and Practical Conference

OIL AND GAS HORIZONS

Dawid Wojaczek AGH University of Science and Technology Cracow

The Second Student International Scientific and Practical Conference o i l a n d g a s h o r i zo n s took place in Gubkin Russian State University of Oil and Gas in December 2010. At the conference students presented their works on five different section related to oil and gas field development, drillings, ecology and economy. Dawid Jach prepared paper titled Mud system used in h d d based on activated bentonite with new polymer PT–51. His supervisor was Sławomir Wysocki, PhD. I presented my Laboratory investigation on use zeolites as natural sorbents in removing pollutants from the drilling waste. My supervisor was Aleksandra Jamrozik, PhD. My work was awarded a special jury prize.

summer / 2 011

Jakub Slek

Conference

Student International Scientific

and Practical Conference

OIL AND GAS HORIZONS

Dawid Wojaczek AGH University of Science and Technology Cracow

summer / 2 011

Dawid Wojaczek

Additionally, at the conference we had possibility to listen to lectures of professionals working in petroleum industry, for example Andrew Mabian from Salym Petroleum and Roland Chemali from Halliburton. We attended English SPEaking Club, where we presented our section and met representatives of Student SPE section from Russia, China and Kazakhstan. We also found time to sightsee Moscow and its monuments. We walked on the Red Square where we have seen the Kremlin and the Lenin’s Mausoleum. We were very impressed by Moscow’s metro stations. Participation in The Second Student International Scientific and Practical Conference o i l a n d g a s h o r i zo n s gave us great opportunity to present our research, hear interesting lectures and meet students from foreign countries. I hope that described event will help our section establish successful cooperation with students from other countries.

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Dawid Wojaczek

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