WINTER / SPRING / 2013
ISSN 2300-1259
85 85
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We are the world’s largest oilfield services company1. Working globally—often in remote and challenging locations—we invent, 1. design, andlargest apply technology to helpcompany our customers find We areengineer, the world’s oilfield services 1. and produce oil and gas safely. Working globally—often in remote challenging locations—we invent, We are the world’s largest oilfieldand services company design, engineer, and apply technology to help our customers find invent, Working globally—often in remote and challenging locations—we 1. We are the world’s largest oilfield services and produce oil and safely. design, engineer, andgas apply technology to helpcompany our customers find 1. We are the world’s largest oilfield services company Working globally—often in graduates remote andtochallenging locations—we and produce oil and gas safely. We need more than 5,000 begin dynamic careers in invent, Working globally—often in remote and challenging locations—we invent, design, engineer, and apply technology to help our customers find the following domains: design, engineer, and apply technology to help our customers find and produce oil than and gas safely. We need more 5,000 graduates to begin dynamic careers in and produce oil and gas safely. n Engineering, Research and Operations the following domains: We need more than 5,000 graduates to begin dynamic careers in n Geoscience and Petrotechnical the following domains: n Engineering, Research and Operations n WeCommercial need moreand thanBusiness 5,000 graduates to begin dynamic careers in We need more Research than 5,000and graduates to begin dynamic careers in n Operations n Geoscience and Petrotechnical theEngineering, following domains: the following domains: n Geoscience and and Business Petrotechnical n Commercial n Engineering, Research and Operations Engineering,and Research and Operations n Commercial Business n Geoscience and Petrotechnical n Geoscience and Petrotechnical n Commercial and Business n Commercial and Business
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What will you be? What will you be? What will you be? What What will will you you be? be?
3
E ditor’s Letter
The times they are a-changing These words from Bob Dylan’s classic ballad are perfectly reflecting current trends in energy industry. We are heading toward cleaner and more efficient energy resources, simultaneously excelling in fields of HSE and social responsibility. Easy access to natural gas from shales contributes to changes in business behavior. For example according to FedEx CEO Frederick W. Smith, the company is likely to shift their truck fleet to natural gas in next decade. We are also changing - during the last two years YoungPetro evolved from being just-acrazy idea sitting in heads of a few students to fully functioning magazine inspiring young adepts of petroleum industry from all over the world. For me being able to work on this project was definitely the most valuable and enjoyable experience over my studies. I was given a chance to meet, work and become friends with many brilliant and creative people thanks to whom the magazine had grown into its current shape. But as all good things my journey with YoungPetro came to an end.
From this place I would like to thank our great editorial board for infinite commitment and thousands of hours of hard work you put into the magazine and all the people who believed in our idea and helped us to do things we thought were impossible. However I am most grateful to you, our readers for being the part of YoungPetro’s community and constant inspiration for our team. I truly hope that you will continue your pro-active way of studying and stay inspired to change the industry, I am sure that Michal Turek and Jan Wypijewski – YoungPetro’s new leaders will help you with that. From the next issue of the magazine Michal and Jan will bring you their fresh ideas and lead YoungPetro to new levels of excellence! Meanwhile in this issue Homer Skokowski will tell you what should be learned from ExxonValdez spill, Adam Szmiłyk will show you what to do with an old oil rig and Richard Awo and Tudor Precup investigate problems of flow assurance in deepwater and arctic fields. Enjoy!
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Editor-in-Chief Wojtek Stupka chief@youngpetro.org Deputy Editor-in-Chief Patrycja Szczesiul dchief@youngpetro.org Art Director Marek Nogiec www.nogiec.org Sales Anna Ropka ads@youngpetro.org
Editors editors@youngpetro.org Iwona Dereń Kamil Irnazarov Maciej Kędroń Karolina Kmak Krzysztof Lekki Homer Skokowski Michał Solarz Antonia Thurmeier Michał Turek Gordon Wasilewski Maciej Wawrzkowicz Joanna Wilaszek
Published by An Official Publication of
The Society of Petroleum Engineers Student Chapter P o l a n d • www.spe.net.pl
Marketing Jakub Szelkowski j.szelkowski@youngpetro.org Barbara Pach bpach@youngpetro.org Logistics Kacper Żeromski k.zeromski@youngpetro.org Jan Wypijewski
Science advisor Tomasz Włodek twlodek@agh.edu.pl Social Media Kacper Malinowski Michał Turek social@youngpetro.org
5
One more lesson to be learned from Exxon Valdez oil spill 7 Homer Skokowski
The Godfather of Oil 15 Michał Turek, Jan Wypijewski
energy-a Modern Day Weapon
19
Hamza Ali
Flow assurance solutions for deepwater and arctic fields 23 Richard Awo, Tudor Precup
Platform Decommissioning 35 Adrian Szmiłyk
Natural Gas in Russia 47 Zakharova Victoria
Successful Matrix Stimulation and Wax Cleaning of a High Water Cut Oil Well of East Potwar Region 52 Mansoor Ahmed Ansari
Initiating the Employee – Employer Dialogue 60 Iwona Dereń
Let’s Shape the Fuel Market – PetroTrend 2013 64 Jakub Szelkowski, Barbara Pach
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̂̂On Stream – Latest News Gordon Wasilewski Shell to suspend Arctic drilling in 2013 Early-march announcement from Shell claims to pause offshore drilling in the Beaufort and Chukchi Seas following series of accidents. In result two drillships had been transported for repairs and would not be able to be fully operational this year. Ships were damaged in movement, not while drilling. Kulluk’s hull has undergone from heavy storm, Noble Discoverer suffered from explosion and fire in port. “Fracknation” – reaproaching fracking Fracking stirs the debate like no other topic, and there are still many myths about it. 2013 documentary “Fracknation” makes a major step to find the truth about it. Film was directed by Phelim McAleer, Ann McElhinney and Magdalena Segieda and has been recorded in USA, UK and Poland. The plot is focused on exposing half-truths and outright lies propagated by films like “Gasland”: burning faucets, earthquakes and contaminated water just to name the few. Directors show lifes of people affected by this propaganda in the most harmful way, like farmers of Dimock, who deprived of help from gas industry due to moratorium in Pennsylvania, suffer poverty, often forced to abandon their farms. The film is remarkable for several reasons: it has been funded by Kickstarter, where people from all around the world were donating small amounts of money for the project. This reflects a promising
fact, that despite all the mainstream anti-fracking campaigning, there are lot of people out there who want more than noisy street protests and Hollywood environmentalism. The second thing “Fracknation” proves is that you can do an anti-environmentalist film and still don’t make it “pro-business pamphlet”, to quote The New York Times. First successful extraction from gas hydrates Japan has successfully extracted natural gas from frozen methane hydrate deposits under the sea, in the first example of production of the gas offshore, officials said on Tuesday. Japaneese scientists used a specialistic technology relayed on reducing pressure in the underground layers which hold the methane hydrate 1330 metres below the sea surface and then they dissolved it into micture of gas and water. Gas is collected through well Talisman Energy may withdraw from Poland Talisman Energy is changing its policy on Polish shales. After ExxonMobil it would be the second player recalculating shale resources unfavourably for Poland’s economy. Divestment options, including in Poland, are being considered. Since 2010 Calgary-based Talisman Energy holds 60% of three shale concessions in Pomerania. Possible divestment would probably mean Polish entrepreneur taking Canadian place.
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One More Lesson To Be Learned from Exxon Valdez Oil Spill Homer Skokowski It was 24th of March, 1989, when the supertanker Exxon Valdez left the port of Valdez bound for Long Beach, California. The captain navigated the ship through Prince William Sound out to the waters of the Gulf of Alaska, the task he had done a hundred times before. Joseph Hazelwood was a proven man, working in Exxon for more than twenty years, ten as an oil tanker captain. Ten minutes after midnight the vessel was supposed to be sailing nearby Bligh Reef. It was then when the ship ran aground, spilling hundreds of thousands of crude oil barrels, thus changing far more than only the Alaskan shoreline. The transformation that occurred in the oil industry, the way it was perceived, regulated and operated, was more profound than it initially seemed.
The Day the Hell Broke Loose Scores of TV crews and reporters from all around the world were going to Alaska and soon photos of animals covered with oil made the headlines of almost every newspaper. And there were plenty of victims: seals, otters, whales, seabirds and eagles died by hundreds and thousands. The sheer magnitude of the calamity paralyzed the first attempts to counteract it. There were many entities with overlapping authority involved: The Coast Guard, the State of Alaska, the pipeline consortium and Exxon. While Coast Guard was supposed to be ready for oil spills cleanup actions, it lacked equipment. Wherever Exxon wanted
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One More Lesson To Be Learned from Exxon Valdez Oil Spill
to bring in its own machinery, the permission was denied by the government. There was a particularly bitter battle about the dispersant, the chemical sprayed from planes over the spill to break up oil into droplets which then can be more easily biodegraded. The local fishermen were strongly opposed to the use of the dispersant, claiming it will only make things worse. In short, Exxon was portrayed as the villain of the piece, with everyone trying to push it away from the case, even though the corporation was capable of helping.
Can It Be Worse? Yes, It Can While the debate about the use of dispersants was going on, forces of nature were preparing to play a little trick in Prince William Sound. 72 hours after the spill a powerful spring
storm went just through the oil-covered waters spreading the spill over the nearby isles, far beyond the initial range. By then it was too late to use dispersant. This would later stand as a ground for accusations that Exxon reacted too slowly or even did not react at all in the first hours after the spill. As if it wasn’t enough to aggravate the situation, captain Hazelwood testified to have been under the influence of alcohol during the grounding. Very soon the ridiculed image of the drunk captain started to serve as an icon of oil industry recklessness. Hazelwood’s number-one excuse, according to a David Letterman Top Ten list: “I was just trying to scrape some ice off the reef for my margarita.” In fact, the Hazelwood was asleep during the collision with Bligh Reef. The case of the captain intoxication only obscured the real cause, or rather a chain of human errors, that led to catastrophe. Inadequate corporation safety systems
Homer Skokowski
contributed much. There was also overload of work due to severe job cuts aimed at boosting profitability and a broken radar.
Bad Reputation Oil industry had bad press since its inception with Standard Oil Company. Exxon Valdez shattered any reputation the business had, leaving everybody, not just Exxon, exposed to the voice of critique of global dimensions. Though, after initial stalemate with government, Exxon swiftly moved to action and proceeded with oil spill cleanup in a highly professional manner. They spent total sum of $2 billion on cleaning and another $1 billion to settle civil and criminal charges. This gave them advantageous position in court and helped to reduce the severity of fines. It is hard to assess total damage done to the brand considering public relations after the Exxon Valdez case. But that was not the end of the story.
Learning the Enemy Exxon Valdez spill posed a great opportunity to study how oil affected wildlife. Media coverage, global scale of the event and the fact, that it happened on American waters helped groups of scientists obtain funding for research. There was Mandy Lindeberg and her team working for the National Oceanographic and Atmospheric Administration (N.O.A.A.). Her plan was to dig seven thousand holes in the beaches affected by the spill, each fifty centimeters deep, and examine them for oil presence. Jeffrey Short was another scientist, who was granted $500 thousand to establish research salmon hatchery, and investigate how sublethal doses of oil affected fishes. He would expose salmon embryos to the oil, and then examine the mortality rates after two years, when fish returned to its birthplace. This was a way to track more subtle and unpredictable causes of death, due to general
9
weakness of the organism. Yet another study was carried out by Jim Bodkin and Brenda Bellachey. They analyzed an enzyme called P450, which level is increased in the liver of an animal exposed to oil. All their work was intently scrutinized by ExxonMobil scientists, who made every effort to undermine unfavorable outcomes. The company’s position was that all the damage was dealt with. Mandy Lindeberg was followed by Exxon’s cruise ship wherever she went. Exxon also used the Freedom of Information Act to obtain the raw data as soon as government paid scientists who had gathered them, to analyze them and to release its own conclusion before the scientists did it. The company sent its representatives to conferences where the reports were presented. They would often stand up and aggressively oppose the results. Company’s situation was compared to that of tobacco industry in early sixties, when dangers of smoking became widely recognized.
What Exxon Valdez Taught Us In spite of all the bad reputation, what Exxon did was sound from scientific point of view. Even the most ardent among their opponents confessed that scientists on Exxon’s payroll where “typically ethical and professional”, and their work was appreciated by them. In an interview Jeffrey Short said: “I think in the wider scientific community we’ve won that battle, […] in fact there’s some really elegant work done by people who are not us. So they [ExxonMobil] can have that position if they like, but most people think it’s flawed.” Mandy Lindeberg could recall one positive aspect of fighting Exxon: knowing that everything she would write or say will be under keen eye of the army of scientific consultants “forced us to be very good scientists.”
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Amoco Cadiz 225 000
Lakeview Gusher 1 230 000 Deepwater Horizon 550 000
Ixtox 1 Oil Spill 470 000
Atlantic Empress/ Aegean Captain 287 000
ABT Summer 260 000
Year
Lakeview Gusher
1910 1978
Ixtoc 1 Oil Spill
1979 1979
Nowruz Oil Spill
Castillo de Bellver
1991 1991
Mingbulak Oil Spill
Atlantic Empress/Aegean Captain
1983 1983
Gulf war oil spill
Amoco Cadiz
ABT Summer
1992 2010
Deepwater Horizon
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Mingbulak Oil Spill 285 000 Gulf War Oil Spill 270 000 – 820 000
Nowruz Oil Spill 260 000
Castillo de Bellver 250 000
Total spillage
= 50 ton
4 289 000
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One More Lesson To Be Learned from Exxon Valdez Oil Spill
What resulted from the clash of the largest company in the world and an army of independent researchers was in fact very good science. Considering all the emotions carried in media reports, both parties managed to stick to the truth. Eventually Exxon had to admit to greater impact of the spill than initially assessed. Lot of oil remained in the ground, just half a meter below the surface. Animals suffered from oil poisoning many years after the accident. Oil toxicity was proved to be much higher than expected. And yet there is something more profound to be learned, especially important now, twenty-four years after the accident. It’s sound scientific dialogue and public recognition of it. This dialogue was present in the Exxon Valdez
case, but fails to be accomplished now in the debate about fracking and shale gas. There are lot of scientists wanting to contribute, but there is virtually no public dispute about it. There are groups of environmentalists, who just ignore the science when facing it, and they have huge public support. They don’t want to study the process, or improve the technology to be more safe or environmentally friendly, they just want the shale gas initiative to be stopped, once and for all. What Exxon Valdez case proves, is that no matter how controversial topic is, how many influential interest groups may be included or how big money is at stake, there is always space for sound reasoning and dialogue based on facts, not emotions or juggling public opinion.
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For online version of the magazine and news visit us at youngpetro.org
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The Godfather of Oil Michał Turek, Jan Wypijewski Everyone knows how the oil and gas industry affects our everyday life, but have you ever wondered–while driving your car or sitting in a warm room when the temperature outside is strongly below 0°C–where it all started? Do you know since when hydrocarbons have been indispensable? Nowadays, top oil-producing countries are Saudi Arabia, Russia and the USA. They produce about one–third world's oil per annum. Therefore your answer about the origin of oil may include one of these countries. If so, you need to be aware that you are wrong. The World's oil and gas industry was born in… Poland in 1853. This year it celebrates its 160th birthday anniversary and it couldn't be in better condition. It all started by accident and because of one person–the godfather of petroleum industry– Ignacy Lukasiewicz. He was born on 8th March 1822 in Zaduszniki near Mielec (southeastern Poland). The important fact is that Poland at that time was split between three countries: Russia, Prussia and Austria. Ignacy Lukasiewicz lived in the Austrian part. He was the son of a poor nobleman, the soldier of Ko-
sciuszko Insurrection–Jozef Lukasiewicz and his wife Apolonia. In 1836 he graduated from secondary school in Rzeszow and then due to family financial problems, he started working in chemist's shop in Lancut and in Rzeszow respectively. That work was interrupted by his imprisonment for underground patriotic activity against Austrians in 1846. He was released from prison after 2 years and then, began working in the chemist's 'Under the golden star' in Lvov. From 1850 to 1852 he was studying pharmacy at universities in Krakow and Vienna. After his studies he returned to his previous employer in Lvov.
Memorable surgery His adventure with oil, as the legend says, started one day in November. Two Jewish innkeepers entered his apartment with a bucket full of unidentified dense liquid from rocks. They asked if there was a possibility to extract alcohol from the unknown substation. During 1852 and 1853 Ignacy Lukasiewicz and
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Jan Zeh were researching on crude oil in their chemist's for technical and lightning purposes. Finally, they received the kerosene. After that Lukasiewicz with Adam Bratkowski invented the first kerosene lamp in the World. Lukasiewicz's kerosene lamp was used for the first time during a surgery at Lvov hospital on 31 July 1853. It is said that the surgery had ended up with a success. After that a doctor was examining the new lamp for some time. He was delighted that it hadn't been smoking. On that day Lukasiewicz made the history. 31 July 1853 is the symbolic date of the beginning of not only Polish but also international oil and gas industry. Soon, the whole city of Lvov was using kerosene lamps to illuminate their homes.
Klobassa. Later that year, they set up the first World's oil mining company in Bobrka, near Krosno. The mine in Bobrka has been opened until now. Lukasiewicz's next step was the opening of the first petroleum refining plant in 1856. The company turned out to be the great success, so he decided to set up several new refining plants.
Right man at the right time
After that he initiated the use of new means of blocking the escape of subsoil and underlying water: lining steel pipes in boreholes, piston pumps with mechanical drives. Thanks to these innovations petroleum extraction begun in the 1860's on a truly industrial scale. By 1862, petroleum had been already flowing from 30 wells operated by 120–150 workers.
In 1854, a man came to Lukasiewicz's pharmacy. He said that he had been buying crude oil from peasants, who had found the spring in the forest near Bobrka. Lukasiewicz decided to visit Bobrka and its landowner Karol
Technological development At the first, the drilling process was rather unsophisticated. A revolution started in 1862 when the engineer Henryk Walter proposed using hand hammer drilling which made use of Fabian's free-fall drilling system.
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Money vs... Simultaneously, Ignacy Lukasiewicz was working on the development of his oil distillation technologies. His oil products were awarded at competitions in Jaslo, Lvov and even in Vienna. The legend says that once upon a time in Vienna, he met John D. Rockefeller. American investor was fascinated by Lukasiewicz's invention, so he proposed cooperation. Lukasiewicz rejected the offer and preferred staying in Poland. He also presented the technology of the kerosene lamp and oil distillation to the future billionaire-to-be who, after returning to the USA, set up the 'Standard Oil' company and became the richest man ever.
...philanthropy The truth is that Ignacy Lukasiewicz didn't care about money. Lukasiewicz used to say: 'Gentlemen, I was born in a threadbare cloak, I have worn it all my life, let me die in it!'. He
was known as a big philanthropist in the local community. He established schools, churches, hospitals and routes. He was a man of creativity, development, social worker and patriot. He died of pneumonia on 7 January 1882 in Chorchowka. In the year of his death, the Karpatians yielded over 20 000 tons of the crude, commonly called oil. To pay tribute to Ignacy Lukasiewicz on the anniversary of the surgery in Lvov–31 July, kerosene lamps bright in every pharmacy.
The motherland of oil The invention of the kerosene lamp, oil distillation process and the setting-up of world's first oil company by Lukasiewicz made Poland the land, where oil and gas industry were born. It was not in Romania where the first attempts at distillation of petroleum were made in 1897. Not in the USA where modern exploitation of petroleum researches begun in 1860. Not in Russia, whose 'oil history' is six years younger than the business of Polish pharmacist and inventor.
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19
̂̂energy-a Modern Day Weapon Hamza Ali
Today we are living in such an age where nations are building their nuclear systems, investing their huge budgets in military weapons signing latest technology-based agreements, they are doing right as safety comes first but this time it will not be a conventional war (if it happens) between nations but rather nations which will destroy opponents using MODERN DAY WEAPON cultural distortion, economic paralysation and capturing and hunting energy resources above all. Following article provides an insight about energy trends, how global energy mix is going to change, what is future of oil, who is the most thirsty for energy and so many more questions. The knowledge of energy outlook is not just a issue for energy companies, policymakers, engineers etc. It’s an issue involving all of us. We all are connected to this global field in one way or another. Oil is the world’s dominant fuel (at 33% of current global primary energy consumption). Oil consumption is dominated by transport sector (more than 50% of global consumption and roughly 60% of OECD consumption); oil has lost significant market share in the power and industrial sectors. As with other fuels, demand and supply have been impacted over the years, primarily by the rate and distribu-
**University of Engineering & Technology ÞÞPakistan hamzaalimirza@hotmail.com University
Country
tion of global economic growth, but also by technological change (such as the emergence of nuclear power or advances in deepwater exploration, development, and production capability); competition from other fuels (cheap natural gas currently).On the supply side, OPEC holds a heavy majority (77%) of global proved reserves. Oil prices have increased in recent years, averaging about $80 in 2010 and well above $100 so far this year, which would be the highest (nominal) price on record.
Population and income growth Population and income growth are the two most powerful driving forces behind the demand for energy. The next 20 years are likely to see continued global integration, and rapid growth of low- and medium-income economies. Over the last 20 years world population has increased by 1.6 billion people, and it is projected to rise by 1.4 billion over the next 20 years; the world’s real income has risen by
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Modern Day Weapon
Energy consumption by power source, 2008
87% over the past 20 years and it is likely to rise by 100% over the next 20 years.
Resource base
Oil - 33.5%
Coal - 26.8 %
Gas - 20.9
Nuclear - 5.8%
Hydro - 2.2%
Others - 10.8%
Percentage shares of oil demand by sector - OECD, 2009
Electricity generation - 3% Transportation - 63% Industry - 24% Residential/ commercial/ agriculture - 10%
Percentage shares of oil demand by sector - global, 2009
Electricity generation - 7% Residential/ commercial/ agriculture - 23% Industry - 18% Transportation - 52%
Another key factor is the resource base. Research work is based on an assessment of global proved reserves for oil, gas, and coal— those quantities that geological and engineering information indicates with reasonable certainty can be recovered in the future from known reservoirs under existing economic and operating conditions. British Petroleum research data clearly shows that global proved reserves of fossil fuels are sufficient to meet expected consumption growth in the decades to come. For oil, world proved reserves at the end of 2010 stood at 1.38 trillion barrels—the highest figure on record. Estimates of oil proved reserves—both in barrel terms and expressed as a reserves/production ratio—have tended to grow over time as new discoveries and improved recovery rates have more than offset volumes produced. We conclude that globally, resources are not likely to be a constraint for oil supply availability over the coming decades. Non-OECD energy consumption is expected to be 68% higher by 2030,and accounts for 93% of global energy growth. OECD energy consumption in 2030 will be just 6% higher than today, with growth averaging 0.3% p.a. to 2030. Now this statistics clearly shows the hunger of particular section of map and also predict the future trade points. Over the next 20 years, role of natural gas is going to be extremely significant (its development, consumption, prices etc). China and India are expected to be large consumers of fossil fuel in next 20 years and consequently will be responsible for maximum carbon footprint. Renewables (including biofuels) account for 18% of the growth in
21
Hamza Ali
energy to 2030. The rate at which renewables are expected to penetrate the global energy market is similar to the emergence of nuclear power in the 1970s and 1980s. Keeping in view the changes in fuel mixture and shift of consumption, energy policy development will gain significance. One of the biggest challenges is to tackle the oil prices and it largely depends on the behaviour of OPEC members. Secondly production rate, continuous supply is/are also required to keep things right. Third policy development should also account the increasing carbon content.
Conclusion Subject of energy seems to be of great importance in the upcoming years as it is one those contents that directly influence our lives and economic strength. Such reports help us to understand the globally changed behaviour about energy and encourage individuals at national level to take adequate steps to prevent future energy shortfall and in this way try to win this war using MODEN DAY WEAPON.
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̂̂Flow assurance solutions for deepwater and arctic fields Richard Awo, Tudor Precup
Abstract The development of deepwater and low temperature arctic fields have become a fore front consideration for many energy companies in recent years especially owing to the rising demand of hydrocarbon and declining onshore reserves. These fields pose great development challenges ranging from their huge financial involvements, complex facilities front end engineering design, operational complexities and assurance of throughput capacity when finally in operation. The later references the fact that multiphased hydrocarbons are typically produced from deepwater fields and transported for long distances to terminals and processing facilities under extremely varying temperature conditions giving rise to chemical reactions which products include; wax, asphaltenes, hydrates, etc which eventually block flow paths, leading to reduction of up-time and production, large redundancy of production systems and increased lifecycle costs. Flow assurance considerations remain a critical aspect to ensuring quicker return on the usual huge investments associated with deepwater and arctic reservoir developments. Several techniques have been employed around the globe to assure the fully capacity of both tubing strings
**Clausthal University of Technology ÞÞGermany roa11@tu-clausthal.de tudor_precup@yahoo.com University
Country
and subsea flow lines are fully utilized. This study stems as a review of the operational principles of Electrical Heating Flow Assurance Systems with the intension of comparing system integrity, efficiency and applicability and associated economics.
Introduction Reservoir hydrocarbon fluid, formation water and associated components exist at reservoir pressure and temperature conditions at a stable equilibrium. When a well is drilled to produce a reservoir changing pressure and temperature results in a disruption of the equilibrium state as the reservoir fluid permeates towards the well and flows into the production system. The fluid naturally attempts to attain a new equilibrium state within the changing environment and the result of this is a phase transition such as gas evolution from the oil, solid precipitation in the hydrocarbon or produced water (Paraffin
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Flow assurance solutions for deepwater and arctic fields
Resin
STERIC REPULSION
ATTRACTION
Asphaltene
Fig. 1 – Forces acting on Aspaltene Molecules [3]
and Asphaltenes), condensation of liquid hydrocarbon from gas and so on. It is generally accepted that any form of solid deposition during the production and processing of oil and gas has unfavorable economic and operational consequences [9]. The phenomenon of phase change which is very typical of deepwater and arctic fields can completely hamper the smooth running of production facilities with its severity increasing with the hydrostatic pressure due to water depth and low sea water temperature (40oF). In order to assure the flow through of the well stream to the process facility, significant investments are made by operators on various flow assurance solutions. Flow assurance is concerned with understanding the risk posed by this phenomenon of phase change and developing and applying suiting engineering solution for the subsea flow lines, risers and the topside facilities in order to mitigate the risk. As a background into what phase change can occur in the sub-
sea production system and what flow assurance problems can ensue, the mechanisms of deposition of asphaltenes, hydrates and wax are explained in the next section.
Mechanism of Asphaltenes deposition Asphaltenes molecules are complex structured hydrocarbon of relatively high molecular weight with density of about 1.2g/cc. These molecules are soluble in aromatic solvents like Benzene and Toluene but are not soluble in n-alkanes (n-pentane, n-heptane) paraffinic solvents. Asphaltenes are polar in nature with the concentration of charges on their surface dependent on the composition of the crude oil. Studies have shown that asphaltene micelles exist in crude oil as colloids which are believed to be stabilized by a protective layer formed by attracting oppositely charged resins (a component of the crude oil soluble in Benzene and Toluene at room temperature)
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Richard Awo, Tudor Precup
to their surfaces and thus prevent the precipitation of asphaltenes. Short distance repulsive intermolecular forces exist between the absorbed resin molecules and the forces keep the asphaltenes from flocculating (see Fig. 1). Any chemical, electrical or mechanical action that deputizes these particles or removes the resin protective layer might lead to flocculation and precipitation of apshaltenes. The Pressure-temperature diagram shown in Fig. 2 presents the asphaltenes precipitation envelope (APE) defining the stability region for asphaltenes in solution. Let the red dot represent a sample reservoir condition. Depletion of the reservoir causes pressure to decline down to the upper limit of the APE also known as asphaltenes precipitation onset pressure. At this point the least soluble asphaltenes will precipitate. Continued pressure decline causes more asphaltenes to precipitate until the bubble point is reached and gas is evolved from solution. With further decrement in pressure, enough gas will be removed from the system and crude oil may
Liquid
During production, asphaltenes can be destabilized and can precipitate due to changes in temperature (to a lesser extent), pressure and the chemical composition of the crude [8]. Deposition can occur throughout the production system from the near wellbore region to the distribution facilities. However, whether asphaltenes causes problems or not is dependent on whether it reaches instability during the production of the crude oil to the surface and transportation to the refinery.
Mechanism of Hydrate deposition In offshore production systems, gas hydrates typically are seen in long flow lines, across gas expansion valves and anywhere in the system where gas and water are present under high pressure and low temperature.
Example reservoir conditions
Liquid and asphaltenes Increasing pressure
begin to redissolve asphaltenes at the lower limit of the APE.
Uppe
r asp
halte
ne en velop e
blepoint)
uilibrium (bub
Vapor-liquid eq
ene phalt
r as Lowe
lope
enve
Liquid and vapor Increasing temperature Fig. 2 – Asphaltene Precipitation Envelope [6]
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Flow assurance solutions for deepwater and arctic fields
Wellhead conditions
Water molecule ‘cage’
Gas molecule (e.g. methane)
Pressure
Hydrates
No Hydrates
Downstream conditions
Temperature
Fig. 3 – (a) Gas hydrate molecule within water cage, (b) Hydrate Precipitation Envelope [4]
Gas hydrates are solid crystalline compound formed when water and gas are combined at low temperature (higher than the freezing point of water) and generally high pressure (e.g. temperatures below 25°C and pressures greater than 1.5 MPa for natural gas hydrates) [11]. Gas hydrates are composed mainly of methane, ethane, propane, CO 2 and H2S. The main frameworks of hydrate crystals are formed with water molecules and appear like ice or wet snow but do not have the solid structure of ice. Enough gas molecules occupy void space in water crystal lattice stabilizing it as shown in Fig. 3. The hydrate formation envelope below demonstrates a typical behavior of reservoir fluids flowing at surface production facilities. The temperature and pressure conditions for hydrate formation in surface gas processing facilities generally are much lower than those considered in production and reservoir. Hydrate formation risks are higher in long tie-back lines. Not only that hydrates can plug
and interrupt production, they also constitute a safety hazard if not properly handled.
Mechanism of Paraffin Wax deposition Paraffin waxes are higher molecular weight components of crude oil that remain dissolved in crude oil under reservoir temperature and pressure conditions and in a state of thermodynamic equilibrium. Like Asphaltenes, any disturbance to their equilibrium state may result in the crystallization of paraffin waxes. The effect of temperature on the solubility of parafin components in crude oil and condensate systems is critical for the mechanism of paraffin wax precipitation. The factor that reduces crude oil temperature contributes to wax crystallization process [5]. Other contributing factor to paraffin wax crystallization is the loss of the volatile (light ends) of crude oil which naturally acts as a solvent, keeping the paraffin in solution. Continued drop in temperature causes the light end solvents
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Richard Awo, Tudor Precup
(n-alkanes) in the crude to become less and less soluble until the higher molecular weight components begin to crystallize.
tain temperature called the Pour Point (PP) where the oil ceases to flow is reached. The WAT, PP and flow rate of the crude oil system are important parameters needed for making flow assurance related decisions [5]. The main options for removing deposits include:
The temperature at which crystallization starts is known as the Wax Appearance Temperature (WAT) or Cloud point. Wax melts at 20oF plus above the WAT. A range of thermodynamic states of temperature and pressure defines an exclusion called the wax deposition envelope (WDE) within which wax crystallization is most likely to occur (see Fig. 4).
Pigging – Cleaning pigs launched into a pipe to mechanically scrape wax from the pipewall and distribute it within the crude in front of the pig. Wax Inhibitors – There are four main categories of such chemical additives: Crystal modifiers, Pour Point Depressants, Dispersants and Surfactants.
Further drop in the temperature of a waxy crude oil system below the WAT results in increasing crystallization as well as increased volume of wax. If the system is left undisturbed, the crystals form a netlike structure which traps oil within it. As this occurrence continues, the oil viscosity and the strength of the netlike structure increases until a cer-
Thermal Techniques – Maintaining or increasing the temperature of the oil above the WAT e.g. by increasing the flow rate the wax deposits will either not be laid down or
Reservoir condition Wax deposition envelope
Hydrodynamic flow path
Hydrocarbon phase envelope
Pressure
Critical Point
Temperature
Fig. 4 – Illustration of Wax Deposit envelope [5]
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Flow assurance solutions for deepwater and arctic fields
will be softened and removed. The proposed solutions in this study are concerned with the thermal solution technique.
the water cut and the flow pressure. Hence flow assurance measures must be taken in due time.
Flow Assurance Solutions
Depending on the section of production system, various techniques ranging from dead oil circulation to active heating systems are in use today. In practice, one technique alone may not entirely solve the anticipated flow assurance problems. For example, the Electrical Heating System (EHS) will not prevent hydrate or wax formation in the subsea trees, manifolds or jumpers as they are not designed to be installed in such systems and the application of the chemical injection techniques may be limited by the water cut of the producing well or limited in efficiency. Hence the choice of a flow assurance solution should be made after a close analysis of the expected well fluid temperature, pressure and composition and the entire production system in order to determine the critical flow assurance points on the system.
In a bid to save the significant cost of oil and gas field development in deep water and in the arctic, many operators have installed subsea production systems with several well streams converging at the manifold channeled through a major flowline tied back to a platform with topside processing facilities. These flowlines run several kilometers on the seabed and are exposed to temperatures near 40°F. The inherent heat of the well fluid is lost to the low temperature of the sea bed environ as the fluid flows through the flowline to topside units. Also, in the case of a planned maintenance or when unplanned conditions necessitate a shutdown, the hot flow from the reservoir is temporarily stopped. During this period, the cold sea bed environment can create production problems in subsea flow depending on
The essence of any effort to employ a flow assurance solution is to maintain the well fluid and flow systems outside the pressure, tem-
Piggyback cable
Seawater
Pipeline
Thermal insulation
Seabed
Fig. 5 – Direct Electrical Heating System [10]
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Richard Awo, Tudor Precup
Current transfer zone 50 m
Current transfer zone 50 m Anodes
Current in seawater
Current in steel pipe Cable joints
Current in piggyback cable Electrical ‘feeder’ cables
Riser
Pipe/cable connection
Supply current
Fig. 6 – Distribution of Electric Current in DEHS [10]
perature and composition conditions appropriate for the formation of Hydrates, waxes and precipitation of Asphaltenes. This study is concerned only with the Direct Electrical Heating System and the Electrically Heated Pipe-in-Pipe (PiP) System. Hence, a description and comparison of these types of Electrical Heating Systems employed today are presented here.
The excess heat left after that lost to the environment will determine how fast the system can raise the temperature of the flowline. The principle of heating the pipeline system is well demonstrated by a manipulation of the Ohm’s law and Watt’s Law to show the amount of useful heat generated in a pipe material by passing am alternating current through the pipe.
The Principle of Electrical Heating Systems
V=I´R [1]
Electrical Heating System (EHS) provides heat to the flowline by supplying alternating electrical current in the pipe wall. As a result of the electrical resistance of the metal pipe to the current flow, the steel gets warmed up and transfers the heat by thermal conduction to the well fluid. Sufficient heat is provided to warm up the well stream in the flowline as well as compensate for the heat lost to the cold seabed environment.
P=I´V
[1]
Where: V – Voltage drop (Volts) I – Electrical Current (Amperes) R – AC Resistance (Ohms) P – Power (Watts) The Electrical resistance of a material is given by the following equation: r=
R A /C × A [3] L
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Flow assurance solutions for deepwater and arctic fields
By rearranging Eq. 3 for and substituting into Eq. 2, the following equation results: r×L ) [ 4] A Eq. 4 indicates the amount of power (useful heated) generated in a conductive material by an electrical current through it. P = I 2 ×(
Two broad categories exist for EHS – the direct Electrical Heating System (DEHS) and the Indirect Electrical Heating System (IEHS –Pipe-in-Pipe). While the DEHS is designed such that the electrical current flows along the pipe wall and the electrical resistance generates enough heat to directly warm up the flowline content, the IEHS has an attached heating element to the pipe surface. Via thermal conduction, this element transmits a portion of the generated heat to the flowline thereby raising the temperature of the flowline content above critical temperatures for wax and hydrates precipitation
Corrosion can also be controlled by maintaining the surface current density of the pipe below a level at which AC corrosion is induced. Field experience shows that a current density of 240A/m2 has been found to be a safe level [10]. Care must also be taken to avoid cracks in the thermal insulation as leakage of currents may occur as a result of variation in impedance along the pipeline. The efficiency of a DEHS is dependent on the cable, power connections, sea water conductivity and the inner pipe electrical and magnetic properties. Design consideration for a DEHS is project and manufacturer specific. However, considerations are generally given to the following parameters: ÈÈ
ÈÈ ÈÈ
Direct Electrical Heating System
ÈÈ
ÈÈ
The pipe to be heated here is usually an active conductor. A single core power cable carrying the total current is strapped parallel to the wall of the pipe. Electrical power source from the platform is supplied to the power cable by one or two riser cables connected by the aid of wet mateable connections. The forward current travels through the cable while the return current is split between the flowline and the sea water. An illustration of the concept is shown in Fig. 5 below. The concept is a single phase system with open insulation. Hence, the need for additional installation of sacrificial anodes (approximately 50m) at the current transfer zones between the cable and pipe to take care straying AC corrosion causing currents.
Material, composition, thermal, electrical and magnetic properties of the pipe. Wall thickness, diameter and length. Pipe insulation – thermal conductivity, U-value (OHTC) and heat capacity Thermal properties, flow rate and composition of the well fluid at different operating modes. Surrounding sea bed temperature, electrical conductivity of sea water and current distribution on the pipeline.
The maximum power (current input) is usually determined and designed for the worst case operational scenario, i.e. heating the flowline to melt a wax plug or hydrates with the insulated pipe lying on the sea bed under the lowest seabed temperature. Fig. 6 shows a schematic representation of the distribution of electric current in the DEHS
Pipe-in-Pipe (PIP) Trace Cable Heating System PIP is an indirect EHS comprising of active heating copper core trace cables stacked to
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Richard Awo, Tudor Precup
the flowline and covered with a high performance passive insulation materials such as mineral wool, microporous silica, or aerogel. The system uses standard single core electrical cables installed in multiples of three along the outer walls of the flowline. At one end of the circuit, one phase of alternating current passes through each of the three cables and at the other end, the three cables are linked to form a kind of star connection such that the sum of the current equals zero. Hence a cable to return the current is not required. Power supply to the cables comes from a dedicated power control unit at the topside which regulates electrical power input within the system. The control unit supplies power to the subsea assembly via a subsea umbilical termination assembly and like the DEHS, the umbilical is connected to the PIP system using standard wet-mateable power connectors and flying leads. Due to a combination of the passive insulation and the location of the trace heating against the flowline wall, the linear power input to meet heating needs is relatively low compared to other systems, in turn allowing a lower total power input or heating over greater distances. See schematic in Fig. 7 below. Technip has developed and qualified this system for static flowlines and steel catenary
risers and intends to install the system for a major operator in the North Sea. However, this study does not include a field case were the system has been installed; rather a comparison between DEHS and PIP is presented in the next section.
Comparison of dehs and pip Trace Cable Heating It is almost impossible to make a strong comparison between DEHS and PIP as they both are basically electrical heating systems. However, there are some non trivial distinctions between them as captured below.
Integrity and Safety The DEHS has an open insulation system which is exposed to the sea water (see Fig. 5) and if not properly insulated; with the passage of time the insulation integrity will be affected [2]. Additionally, the return electrical current of the system split between the sea water and the pipeline surface if higher than the corrosion inducing current density could
Carrier pipe Second layer passive insulation Fiber-optic cable
Flowline First layer passive insulation Centralizer
Fig. 7 – Electrically Trace Heated Pipe in Pipe [7]
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Flow assurance solutions for deepwater and arctic fields
cause a corrosion of the pipeline especially at the current transfer zones. Also, any earth fault on the cable could generate enough heat which may damage the pipeline violating the integrity of the production system. At the downstream end of the PIP system is a star connection with a net current equal to zero. By the nature of this design, no current flows into the sea water thereby providing a high level of reliability taking into consideration the extended lifetime requirement of such a system. Monitoring of the temperature profile along the flowline is achieved by the use of optical fiber distributed temperature sensing (DTS).
Efficiency and Applicability The PIP incorporates a high high-performance trace heating system and a passive insulation thereby providing a very high heating efficiency and a low overall heat transfer co-efficient OHTC (between 0.5W/m2.K and 1.2 W/m2.K). Another attractive advantage is that for wells flowing by the aid of ESP, during a shut down phase the power supply of the pump can be diverted and used for pipeline heating. Another significant benefit to the PIP is their low power requirement (30 -100 W/m for warm up and 10 – 30 W/ for temperature maintenance above critical levels) which make them suitable for long tie backs as well as reduces both CAPEX and OPEX for the producer. As soon as the production system is shut down for any reason, the DEH can be immediately activated to preserve the heat of the well fluid. Chemical injections must be used for non- electrically heated sections of the production system such as Subsea trees, manifolds and Jumpers. Efficiency of the DEHS is much dependent on the piggy back cable distance to pipe, power frequency and seawater return path. Because it is one-phased, it does
not provide a uniform heating of the flowline stream as heating is more intense on the topside where the piggy back cable is strapped to the flowline.
Cost and economics The configuration of PIP system consists of the flowline, the heating cable, two layers of insulation materials and the outer carrier pipe. The implication is that the pipes are often of larger diameter than the DEH systems which do not contain an outer pipe (see the insert of Fig. 5) and will definitely attract more procurement and installation cost than the DEH system. The double insulation layers (made of PCM) of the PIP make it an attractive option for increasing flow line cool down time. The PCM material is hydrocarbon based, with a transition temperature of 28o°C. Its energy storage capacity is of 143 MJ/m3. With a 43mm thick PCM layer, the cool down time performance of the PIP is increased by 2.7 days approximately [1] In general terms however, the cost of either system is mostly dependent on the tie back length and the method selected for the installation of the system.
Conclusion For the next few decades of fossil fuel development, oil and gas production from deep water fields will continue to stride and flow assurance challenges will also increase. Whether EHS design to be retrofitted or as part of a new subsea production system it will remain a major flow assurance solution for warming up or keeping flowline content temperature above the critical hydrate and wax formation levels and will continually help to reduce CAPEX/OPEX for operators by
Richard Awo, Tudor Precup
encouraging more tie backs and eliminating the need to construct a cost intensive floating platform. Besides the EHS, there are also other options like Chemical injection (Thermodynamic and Kinetic inhibitors), hydraflow concept, dead oil circulation, pigging, etc. The task lies in
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the hand of the design engineer who must understand the nature of the subsea environment and proffer a lasting solution to flow assurance challenges. The key to selecting an appropriate system is specific to the project development strategy and expected project deliverables.
References 1. Sylvain Denniel, Technip Offshore UK Limited; Jerome Perrin, Genesis France; Antoine Felix-Henry, Flexi France “Review of Flow Assurance Solutions for Deepwater Field” Paper SPE 16686-MS presented at the Offshore Technology Conference, Houston, Texas, USA, 3–6 May 2004. 2. Rebecca Fisher Roth, INTECSEA, “Direct Electrical Heating of Flowlines–A Guide to Uses and Benefits” Paper SPE 22631-MS presented at the Offshore Technology Conference, Rio de Janeiro, Brazil, 4–6 October 2011. 3. Tore A. Garshol “Investigation of Apshaltene precipitation mechansism on the Gyda Field”. Project Work submitted to Department of Engineering and Applied Geophysics, Norwegian University of Science and Technology, December 2005. 4. R. Azarinezhad, A. Chapoy and B. Tohidi “Novel Technique for addressing gas hydrate and flow assurance: Cold flow and Hydraflow”. Centre for gas hydrate research Heriott Watt University Edinburgh, Devex Aberdeen, 12–13 May, 2009. 5. Tarek Ahmed. “Equation of state and PVT analysis: Application for improved reservoir modeling” Gulf Publishing Company, Houston Texas, Chapter 6, Page 496, 2007. 6. Schlumberger Online. (August 2012) http://www.slb.com/~/media/Files/resources/oilfield_ review/ors07/sum07/p22_43.pdf 7. Technip Rigid Pipe Technology online. (September 2012) http://www.technip.com/sites/default/files/technip/publications/attachments/ETH-PIP_WEB.pdf 8. Oilfieldwiki Online (August 2012) http://www.oilfieldwiki.com/wiki/Asphaltenes#cite_note-0 9. Leontaritis K J, Mansoori G A. Journal of Petroleum Science and Engineering, 1988, 1: 229 10. Herald Kulbotten “DEH–Basic Technology” SINTEF Energy research, Gas hydrates operational treatment and futures scenarios Tekna 21–22 October, 2008. 11. C. A. Koh, R. E. Westacott, W. Zhang, K. Hirachand, J. L. Creek and A. K. Soper “Mechanism of gas hydrate formation and inhibition”, Department of Chemistry, King’s College, London, 4 September, 2001.
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35
̂̂Platform Decommissioning Adrian Szmiłyk
Introduction The beginning of "platform life" is the oil rig project. Designing marine rig is a very responsible job because each piece of equipment can determine the life of the crew. When the design is finished, the work in construction yard starts. Then the platform is transported to your destination. Rigs are towed as a whole, using tugs or are divided into components, which are transported by barges or ships. The most important stage of "platform life" is the extraction of the platform, which can take several years. But as everything in the world rigs also have limited lifetime after which there is a need for withdrawing it from use. It is a very complex procedure requiring a balance between factors such as technology, environment, cost, safety, regulations and social responsibility. These factors allow you to decide what happens to the platform–whether it is completely removed, embedded or can be used to create artificial reefs.
**AGH Univ. of Science and Technology ÞÞPoland szmilykadrian@gmail.com University
Country
drilled and completed almost 100 years later– in 1947. This event started new era in oil a and gas industry. The offshore as well as onshore operators install their facilities and equipment required to produce hydrocarbons. When the hydrocarbons are no longer economic to produce and facilities and equipment are redundant they are becoming subject of removal and disposal. [1] The first documented removal was in GOM. Since 1973 more than 1200 structures have been retired from GOM.
Short History
After plans of dump Brent Spar [Fig.1] in deep waters and illegal intervention of environmental activists the removal of offshore structures from site for disposal on shore for recycling or reuse in other production operations or converted to use other than initially designed for, has been the normal practice. [1]
The oil and gas industry had its beginning in 1859. The first offshore well in the Gulf of Mexico (GOM) out of the sight of land was
Nowadays Brent Spar is an icon for the decommissioning process on a worldwide scale and brought world attention to this process.
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Thanks to environmental activists in June of 1995 the decision was made not to continue with sea disposal.
Balancing Factors The choice of the method to be used for platform decommissioning and removal depends on many factors. It is important to strike a balance between the six major factors : technology, environment, cost, safety, regulations and social responsibility (Fig. 4). Technology Technology is a big challenge for engineers. Dismanting the platform requires them to
Platform Decommissioning
prepare a detailed treatment plan and to find technical solutions. Platforms are very large and heavy structures. Process of rig removal is even more difficult because of limited access to the crucial high capacity equipment (lift vessels, towers, etc). There are lots of such lifts in the world, which are scheduled to work almost 24/7, and cost of ownership is high. When you dismantle the structure barges are needed to transport the data elements. The actual offshore abandonment and removal activities are performed in the following sequence: shutdown, well abandonment, decommissioning, deconstruction, lifting/handling, transportation, material disposal, final survey.
Fig. 1 – The Brent spar, resting in a Norwegian fjord
Adrian Szmiłyk
Environment To remove the platform we need heavy marine equipment, which during operation emits large amounts of CO 2 into the atmosphere. Another problem is that not all removed items are suitable for recycling so probably will be stored on land. We have a clean seabed, but we must consider whether there is, in some cases, a potential risk of environmental contamination on shore. Goliat is the first oil field to be developed in the Barents Sea, and thus sets the industry standard as activity migrates ever further north. The Goliat FPSO is built and equipped to meet high standards linked to in-built safe-
37
ty and a healthy working environment adapted to the climatic conditions in the Barents Sea. The FPSO will be especially designed for environmentally friendly operations and energy recovery. Electrification from shore will provide reduced emission of CO 2 and the oil containment system with segregated ballast tanks and no contact between oil and water preventing the release of polluted ballast water to the sea. The oil containment system will also be protected by ballast tanks in the sides and bottom area. The specially designed winterization solution will provide good working conditions for the crew.
Fig. 2 – Partially disassembled platform
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Fig. 3 – Perenco UK executes the heavy lift removal of the Welland gas production platform in the southern North Sea
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Platform Decommissioning
Decision of platform decommissioning
Six major factors: - technology – environment – cost – safety – regulations – society
choice of plaform decommission method
Fig. 4 – Balancing Factors
Costs Cost must not to be disregarded just to obtain a desired goal. Society functions as a result of prioritizing expenditures. Regardless of who spends the money, it is society who pays in the end through higher taxes, higher prices, less employment opportunities, reduced pensions and reduced dividends. Removal to shore at any cost is not prudent for society in the long term. [1] The cost of renting a heavy lift vessel (Fig. 3) with a capacity of lifting several tons and barges to transport it ranges from a few dozen to a few hundred thousand dollars for one day.
regulations in a global issue context, is much more important today than it was in 1995 before the Spar. [1] The explosion of the Deepwater Horizon drilling rig in the Gulf of Mexico on 20 April 2010 and the subsequent massive leak from the oil well on the sea bottom and sinking caused significant environmental, economic and social damage. The Deepwater Horizon spill exposed a variety of regulatory failures by the federal government. After the spill, critics attacked regulators for an inadequate environmental review process under the National Environmental Policy Act (NEPA).
Safety Removal of platform is a very dangerous process. During this operation, proceed step by step in accordance with the guidelines, because even a small deviation can result in tragedy. Every second during the operation endangers human life and therefore procedures must be rigorously adhered to. Regulations National and International regulations on the decommissioning of abandoned or disused offshore oil and gas installations have in the past years gone through a metamorphosis. [2] Decommissioning is a global issue and an understanding of the regional and national
Policymakers also attacked the Minerals Management Service’s (MMS) numerous conflicts of interest with the oil industry. This Comment, however, focuses on the federal government’s failure to implement a regulatory regime mandating adequate safety and cleanup technology in deepwater oil exploration. Ultimately, this Comment seeks to remedy this failure by proposing a regulatory regime that implements a Best Available Technology (BAT) standard for deepwater oil exploration safety and cleanup technology. [6] GOM as well as North Sea are the most experienced areas in the world in platform decommissioning.
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Adrian Szmiłyk
Social Responsibility Nowadays the society is a very important element. Citizens want to have more and more influence on the decisions made by politicians. Industry must show the people that it’s operations are performed in accordance with all laws and regulations, and are safe for the environment. If industry will be considering society’s voice, they will gain people trust, and trust is an essential element of cooperation.
Options for Decommissioning Steel Jackets are by far the most common type of offshore platform. The majority of jackets are small to medium-size platforms in water depths less than 75 m and weights less than 4000 tones more than half of them are in GOM and North Sea. [3]
platform or debris still remaining on the sea bottom. This solution is preferred by governments and other sea users because it solves most problems connected with abandoned platform: safety of navigation, commercial fishing, environmental interests and national security. The complete removal, which is sometimes very expensive, is not favored by the oil industry. [4] Partial Removal This solution is allowed for large structures. Any piece of platform equipment must be cut and removed in section by Heavy Lift Vessel and seated in the load spreaders and secured to the deck of the cargo barge. The jacket is cut to the required depth leaving the bottom portion on the sea bed. Pieces of platform may be taken to a deepwater disposal site, transported ashore for recycling or onshore disposal. Toppling
Several removal solution for decommissioning of jackets : ÈÈ complete removal ÈÈ partial removal ÈÈ toppling ÈÈ reuse ÈÈ alternative use Complete Removal
The toppling of the entire platform involves explosive cutting of selected rig parts in such a way to cause the platform to fall over onto the sea bed. This procedure is finished by leaving the required navigational clearance above the toppled platform. This alternative would be the most economically attractive solution, but it involves problems of engineering to ensure that toppled pieces fall as wanted and that environment, safety and social responsibility issues are considered.[4]
Complete removal leaves a clean sea bed as found before the platform installation. Exception may be done only with the buried facilities (as foundation piles, conductors, portion of pipelines, etc) and concrete gravity platforms.
Reuse
This option requires structure to be entirely removed by lifting either in one piece or in sections depending on the size of the jacket and the capacity of the lift vessel. The final survey will locate and remove any piece of
The opportunities for reuse of platform at another field site are limited as they are designed for specific production requirements, water depth, environmental criteria and soil conditions. The reuse of decommissioned
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platforms gained popularity in the 1980’s with the emergence of small operators and development of smaller, short life fields. GOM facilities in water depths less than about 90 m and less than 15 years old are typically considered for reuse. [3]
Platform Decommissioning
Conclusion Platform decommissioning is a very complex process. There should be a balance maintained between six very important factors, which unfortunately is not easy to achieve.
Alternative Use Perhaps the most successful alternative use for a decommissioned platform are artificial reefs. The structure may be toppled in-situ or cut into pieces and placed on the sea bed in a designated area to provide a marine habitat. One of the most extensive experiences is using decommissioned platforms as artificial reefs. In Gulf of Mexico more than 140 platforms have already been emplaced. [3] Another way is leaving the rig in place. This option may be attractive for a small number of platforms, which would be extremely difficult to remove (for example enormous concrete gravity platforms). Other options for decommissioned platforms include use for eco-tourism sites, aquaculture and general tourism activities, research centers and attraction for recreational divers and fishermen.
The oil industry should strive above all to consolidate the law relating to decommissioning process that among other things would require each operator to establish a special fund for the liquidation of the platform. It is a very difficult task to do but nothing is impossible. Platform decommissioning is also a big challenge for engineers. The sea conditions to remove such a large machine are very complicated. Therefore, platform designers should note also the final phase of 'life platform" and so certain elements of design to decommissioning became safer, faster and above all cheaper. I encourage everyone to pay attention to this issue because it is a relatively young but very powerful, both technologically and decision-making process that is constantly evolving and requires knowledge and experience of many engineers.
References 1. William S., Griffin, Managing the Platform Decommissioning Process, SPE International Conference and Exhibition in China held in Beijing , China, 2–6 November 1998. 2. Igiehon M.O., Evolution of International Law on the Decommissioning of oil and Gas Installations, SPE/EPA/DOE Exploration and Production Environmental Conference held in San Antonio, Texas, 26–28 February 2001. 3. Anthony N.R., Ronalds B.F, Platform Decommissioning Trends, SPE Asia Pacific Oil and Gas Conference and Exhibition held in Brisbane, Australia, 16–18 October 2000. 4. Della Greca A., Offshore Facility Removal: How to Save Cost and Marine Resources, SPE European Petroleum Conference held in Milan, Italy, 22–24 October 1998. 5. Jørgensen K.O., Decommissioning of The Ekofisk I platforms, Offshore Conference held in Houston, Texas, 4–7 May 1998. 6. Bush J., Addressing the Regulatory Collapse Behind the Deepwater Horizon Oil Spill: Implementing a “Best Available Technology” Regulatory Regime for Deepwater Oil Exploration Safety and Cleanup Technology, http://law.uoregon.edu.
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47
̂̂Natural Gas in Russia Zakharova Victoria
Natural gas has been known since ancient times, but its use was not widespread. The first evidence of the use of gas as a fuel, apparently, Marco Polo left in his book about traveling to China (XIII c.). In industrial applications the gas was used in 1872 in the U.S.A. In Russia, the use of natural gas as a fuel began only after the October Revolution (1917). During the Second World War in the Saratov and Kuibyshev region natural gas deposits were discovered, the extraction and use of which marked the beginning of the Soviet gas industry. The USSR's first pipeline Saratov–Moscow went into operation in 1946. After oil having been discovered, for decades gas has been considered its useless byproduct and was vented to atmosphere or flared. But at the present time the natural gas industry is experiencing rapid growth thanks to the diverse use of natural gas as a fuel and a feedstock for the petrochemical industry. Currently, natural gas is a major source of energy. Russia takes first place in the world in exploration and production of gas. Natural gas production in Russia in 1990 almost did not decrease and remained at the level of 600 billion m3 .
**Gubkin Russian State Univ. of Oil and Gas ÞÞRussia zakharova.victory@yahoo.com University
Country
Their main deposits are located in West Siberia, Volga-Urals, Timan-Pechora and the Northern Caucasus and the Far East. In Russia gas production is intended for domestic consumption and for export to other countries. About 30-50% of the extracted natural gas is intended for export, which will regularly replenish the budget of the country. Russia is the largest exporter of natural gas. It is the only supplier of gas to Estonia, Latvia, Lithuania and Slovakia, it provides 80% of the gas needed in Hungary and Poland, more than 70%–in the Czech Republic, 65%– in Turkey, 42%–in Ukraine, and 40% and 25% in Germany and France respectively. An increasing number of the reservoirs is located offshore, in poorly accessible areas, often far away from the major consumption sites. The industry faces therefore great technical and economical problems of transporting natural gas to the consumers.
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Natural Gas in Russia
Natural Gas Producers
The three types of natural gas are generally distinguished: 1. nonassociated gas which is not in contact with oil 2. gas cap–associated gas overlying the oil phase in the reservoir 3. associated gas "dissolved" in the oil in the reservoir (dissolved gas)
Russia
USA
Canada
Others
Qatar
Iran
Natural Gas Net Exporters
However, there is more than the type of natural gas and the properties of oil with which it may be associated – what is the most important factor is the chemical composition of the gas. It affects the processing that the gas will have to undergo to meet the specifications of its transportation by pipeline or in the form of LNG (liquefied natural gas). Natural gas from different deposits varies. The knowledge of the composition and the properties of natural gas is essential at all stages of production, processing, transportation and storage. The characteristic features of natural gas:
Russia
Qatar
Norway
Canada
Algeria
Others
Natural Gas Net Importers
1. It is difficult to form compounds with other elements or substances 2. The gas atoms are not connected to the molecule, these molecules are monatomic 3. Natural gas atoms are characterized by high values of the ionization energy and, as a rule, a negative value energy facilities to electron Generally, the higher the molecular weight of the hydrocarbon, the less of it is contained in natural gas.
Others
Korea
U.S.A.
Germany
Italy
Japan
Fig. 3 – Key world energy statistics 2012
Natural gas is transported by pipelines as compressed gas or liquefied gas. Gas at the pressure of 75 atmospheres flows through the pipes. Over the gas pipeline it loses energy, overcoming the force of friction between the gas and the tube wall, and between the layers of gas. Therefore, after a certain period it is necessary to build compressor stations at which the gas is squeezed up to 75 atm.
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Zakharova Victoria
Natural gas produced in Russia is delivered into gas pipelines, integrated in the Unified Gas Supply System (UGSS) of Russia. UGSS is the world's largest gas transmission system and represents a unique technological system that includes gas extraction, processing, transportation, storage and distribution facilities. UGSS provides a continuous cycle of gas from the wellhead to the end user. Unified Gas Supply System of Russia belongs to "Gazprom".
Fig. 4 – Cryogenic storage
South Stream is a new project by Russia-Italy-France-Germany, aimed at strengthening the European energy security. All the pipeline will be enough to go around the Earth 4 times
lection and gas injection, the period of storage at maximum capacity.
Natural gas storage is necessary for the seasonal regulation of consumption and gas supply, as demand for heating, for instance, is different in winter and in summer. Gas storage is a geological structure or artificial reservoir used for gas storage. Work of storage is characterized by two main parameters–volume and power. The former describes the storage capacity–the active and buffer gas volumes, the latter shows the daily performance of se-
ÈÈ
Two main storage methods are employed:
ÈÈ
cryogenic storage in gas-holder, as LNG underground storage in depleted reservoirs and salt cavities.
There are more than 600 underground gas storage in the world Underground storage in salt caverns is used primarily to cover peak loads, because they can be operated in the "jerk" mode with the
Fig. 5 – Underground storage
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Natural Gas in Russia
Field name
Field type
Opening Year
Gas Reserve (m3)
Zapolyarnoye
condensate gas and oil
1965
0.7 trillion
Sakhalin-3
oil and gas
1992
1.4 trillion
Rusanovskoye
condensate gas
1992
3.0 trillion
Leningradskoye
gas
1992
3.0 trillion
Stockman
condensate gas
1988
3.7 trillion
Bovanenko
condensate gas and oil
1971
5.9 trillion
Yamburg
condensate gas and oil
1969
8.2 trillion
Urengoy
gas
1966
10 trillion
Table 1 – The most important gas fields in Russia performance of selection; the order of selection of the gas storage capacity in porous structures, and the number of cycles can be up to 20 a year. For these reasons, the creation of the gas storage in salt has received much attention in the developed world. It is also associated with market conditions and the functioning of the gas, as the gas storage in salt can be used to compensate for shortterm fluctuations in gas consumption, to prevent penalties for imbalance in the supply of gas due to gas pipeline accidents, as well as procurement planning at the regional level, according to the monthly or daily fluctuations in gas prices. The situation of Russian gas industry is unique–in fact, all public functions are delegated to one of the economic entities–Gazprom, the activity of the state is limited to the
regulation of gas prices in the country. Gazprom controls 60% of gas reserves in Russia. It accounts for 84% of Russian gas production, and nearly 100% of transportation At the present stage of the natural gas industry one of the most important elements of the economy of the Russian Federation is the reliable operation on which its further economic development depends. In the coming decades, natural gas will continue to strengthen its position in world energy. According to the International Energy Agency, the share of gas is now 22% and will continue to grow due to the continuing increase in demand. Over the past ten years, the demand for gas has shown the average annual growth of 2.5%. By 2030, its consumption is expected to double.
References 1. 2. 3. 4. 5. 6. 7. 8.
Architektura Russia – http://apxu.ru, Web 2012. Gazprom Company – http://gazprom.ru, Web 2013. International Energy Agency – http://iea.org, Web 2013. Russian Modern Library – http://modernlib.ru, Web 2013. Young Scientist - Monthly Scientific Journal – http://moluch.ru, Web 2012. Russian National Political Encyclopedia – http://politike.ru, Web 2012. Technical Journal of Ukraine – http://tehnichka.com, Web 2013. The probing - Analytical Search Portal – http://zondir.ru, Web 2013.
52
̂̂Successful Matrix Stimulation and Wax Cleaning of a High Water Cut Oil Well of East Potwar Region: A Case Study Mansoor Ahmed Ansari
Abstract Effective acid diversion across high permeable and fractured carbonate reservoirs have always been challenging and even more complicated when stimulating high water cut wells. In these type of wells, the challenge is to stimulate the oil-bearing zones rather than the water-bearing zone. To achieve the diversion, polymer-based diverters were had been used earlier which resulted in lower efficiency. In the case study discussed in this paper, a polymer-free diverter (Non-Damaging and Diverting Acid System) was used to divert and effectively stimulate the target formation. The target formation has been produced at high water cut which was highly sensitive to the pressure drawdown applied at the formation face. The prime objective of the treatment was to reduce the formation-face drawdown by treating near wellbore damage, so that the reduction in water cut and the increase in oil rate could be achieved. The acid treatment of 15%HCl with polymer-free diverter system was used for efficient and well controlled matrix stimulation. The system consisted of a self-diverter which forms a gel as acid spent, and temporarily blocks the pore throat allowing efficient diversion of the
**NED Univ. of Engineering & Technology ÞÞPakistan mansoor_ansari@yahoo.com University
Country
main acid to the oil bearing zones. When it comes in contact with hydrocarbons, it starts breaking, leaving the pore throat clean. Wax/ Asphaltene clean out program is also carried out with organic solvents inside wellbore and production tubing. Well tests were performed before and after the stimulation treatment. The results of the tests indicated an increase of ≈130 bbl/day in oil production with decrease of water cut to zero. The increase in oil production and elimination of water cut shows the success of the stimulation treatment.
Introduction Matrix acid stimulation has been used for decades as an excellent technique to improve production of oil and gas wells. It improves the production by decreasing skin, bypassing the damage zone or creating worm holes in carbonate formation. Every stimulation job requires deep concentration for its designing which will lead to success. Over the years,
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Mansoor Ahmed Ansari
250
Viscosity (cP)
200 150 100 50 0
0
5
10
15
20
HCl % (volume) spent
Fig. 1 – Polymer free divert system viscosity for spent system
stimulation jobs have been designed to target oil zones and damaged zones. In an active water drive oil reservoir, the major concern is to prevent the water zone from stimulating fluid. With water cut fields, successful stimulation treatment involves reviewing the well history, reservoir characteristics, and potential production results before selecting the optimum stimulation treatment [1]. However, there is always a risk of stimulating the water zone.
wards the damage or low permeable interval. Due to high permeability and damaged zones, diversion is highly recommended in these reservoirs.
The target formation is a highly fractured carbonate reservoir having high secondary permeability. Permeability of the reservoir varies from 330md to 870md. Due to high permeability, uniform stimulation with the use of conventional stimulation techniques is difficult. Effective diversion is the key for the success of stimulation treatment to achieve uniform treatment. Without diversion, acid seeks the path of least resistance and moves only in a small portion of the whole interval. Chemical diverting agents
Conventional stimulation treatments use regular acid or retarded acids [2, 3] in conjunction with chemical diverters including foams [4] to fully stimulate long, non-uniform carbonate formation. The most commonly used chemical diverters are polymer-based [5], and they are associated with induced formation damage [6]. To perform the stimulation of entire zone uniformly a polymer-free diverter system has been developed. The system is supplied as an active solution. Upon addition to an aqueous brine solution or upon acid spending into the formation, the Gelling Agent will generate an elastic gel. The gel will break upon contact with isopropanol or other hydrocarbon fluids leaving back a clean formation matrix with almost no impairment to original matrix permeability and eliminates the concern of ineffective stimulation.
temporarily block the undamaged or high permeable interval and divert the acid to-
Stimulation by coiled tubing was shown to be the best tool for acid placement and to
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Successful Matrix Stimulation and Wax Cleaning of a High Water Cut Oil Well
get maximum coverage [7, 8]. Because of the non-damaging and effectiveness as diverting agent polymer free diverter system is selected for stimulating the well in the targeted formation of the field. As targeted formation contains high wax content due to which VLP of the well is deceased, therefore to improve it, a wax cleaning program with toluene and diesel in the ratio of 70:30 is also carried out.
conning due to excessive drawdown which may be due to skin and wax deposits. The treatment is designed to improve well deliverability to minimize drawdown and water coning and also to clean up the wax deposits in the tubing to improve VLP and prevent choke plugging.
The Carbonate Challenge Carbonate matrix stimulation has been extensively researched and discussed in numerous publications [9, 10].
The Field The target formation is a fractured limestone formation, which has secondary porosity. It encloses considerable amount of oil but as we produce it, water encroachment occurs as reservoir is supported by an active edge water drive. It has a net pay thickness of 90m. It produces crude oil, which has 33°–35° API Gravity. The GOR at the separator is about 1931 scf/STB. So the extracted crude oil can also be known as Black Oil.
With the selection of right stimulation fluid and injection rate, one more important consideration is the diversion of the stimulation fluid across the reservoir, not only the high permeable layers or less damage interval. In general, two ways of diversion are available namely mechanical diversion and chemical diversion.
The well was completed in 2005. Continued production from the well resultes in water
Tools are run inside the well bore which provides mechanical diversion to the stimulating
Mechanical diversion
Oil rate (bbl/day)
40 200
30 20
150
Water cut (%)
50
250
10 100
Jun 3, 10 Dec 3, 10 Jun 3, 11 Dec 3, 11 Jun 2, 12 Dec 2, 12
Time
0
Water cut (%) Oil rate (bbl/day)
Fig. 2 – Well Production History
Mansoor Ahmed Ansari
fluid. Typically used mechanical diverters are Packers and bridge plugs, ball sealers or jetting devices. Packers and bridge plug has been used with success in through tubing operations. Packers and plugs are set between the targeted intervals which provide mechanical separation between two intervals. But they require extra time and cost for placing and removal. Balls sealers shut off individual perforations from taking fluid. When we pump the balls, these will set in the perforations at a minimum differential pressure. Usually a large number of balls is needed to be pumped which is burdensome activity. It cannot be used in open hole completion. Jetting devices are popular for use with coil tubing devices and direct the flow towards the concentrated streams. The impact force and direction of nozzle is used to place the acid at desired location. Due to diameter restriction we can not use it. Chemical Diversion Fluid viscosity and solid particles are used to create the resistance in the flow of acid in undesired interval.
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Polymer diversion is based on the differential pressure created between a zone that accepts the polymer and a zone that does not accept the polymer. Some polymers are nonreactive. Others are self-diverting–it increases its viscosity at particular pH and decreases its viscosity when the acid is spent. The problem is the small pH window for the treatment. Foamed fluid consists of liquid and gaseous phases which form required differential pressure in the formation. Several authors have shown cases where properly engineered foams remained stable in water-rich environment, while emulsion was separated in phases in oil-saturated layers [12, 13]. The drawback with foamed diverter is that it requires nitrogen tanks and extra pumping unit. Polymer-free diverter system shows similar properties. The major advantage of this system over conventional acids is that it is non-polymeric and non-damaging. Unlike other diverting materials, such as foam and particulates, this system can be pumped as a single fluid, which will stimulate and divert in one step. Alternatively, it can be pumped in several stages with regular or retarded acid stages. Also, this fluid can be used for the stimulation of wells with a BHST of up to 400 0F. [14]
Particulate or thin film-forming agents were widely used in the early stage of matrix stimulation. Particles such as Benzoic acid, rock salt or oil soluble resins are used to form a temporary layer which diverts the acid towards damage interval. This occurs independently of fluid in the formation [11].
The normal additives like corrosion inhibitor, chelating agent and iron control agent are compatible with this system. When stimulating carbonate reservoir HCl reacts with CaCO3 and creates worm holes
The other group of chemical diverters consists of viscous fluids. As it enters the formation due to its viscosity it diverts the acid towards damage interval.
Calcium chloride is produced while the acid is spent. Upon acid spending into the formation, the gelling agent will generate an elastic gel. This elastic gel increases the viscosity (see Fig. 1). The resulting high viscosity creates temporary blocking of the pores and diverting the acid towards un-stimulated interval. The gel will break upon contact with isopro-
Viscous diverters consist of three main groups, namely polymer-based fluids, foamed fluids and non-polymer fluids.
CaCO3 + HCl ® CaCl2 + CO2 + H2O [1]
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Successful Matrix Stimulation and Wax Cleaning of a High Water Cut Oil Well
3000
130 bbl/day increment
FWHP (psia)
2500 2000 1500 1000 500 0
0
50
100
150
200
250
300
350
400
450
500
Oil rate (bbl/day) Pre-Treatment Testing
Post-Treatment Testing
Repeat Testing
Fig. 2 – Well Production History
panol or other hydrocarbon fluids leaving back a clean formation matrix with almost no impairment to original matrix permeability. Post flush of a mutual solvent will also help in break and flow back of treatment fluid.
which significantly reduces the operation complexity.
Since this system does not viscosify in the tubing string, it can be easily pumped through coiled tubing in both cased and openhole completions. Polymer-free diverter system contains no solids that could bridge when pumped through coiled tubing. With CT, this system provides the best results when diverting in carbonate reservoirs. It can also be used for stimulating horizontal wells. Unlike other diverting materials, such as foam and particulate, polymer free diverter system can be pumped as a single fluid stage, which will stimulate and divert in one step. It can also be pumped in several stages alternately with regular or retarded acids. This self diverting acid combines the capabilities of stimulation and diversion in one process,
The well was drilled down to a depth of 2274m in the targeted Formation. Although the primary objectives were other formations, the well was completed as a dual string producer from the Formation, in 2005, due to its encouraging test results. The formation is known to be an oil bearing carbonate and has generally demonstrated significant pressure support due to the presence of a strong aquifer. The well is an open hole completion having reservoir pressure of 4440 Pisa and BHT of 185°F.
Case Study of The Well
Pressure transient testing was carried out in a DST at the inception of the well. Though the entire data set could not be matched using a single set of variables, the general consensus
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Mansoor Ahmed Ansari
was that the reservoir permeability was high, with a moderate skin. Continued production from the Reservoir had resulted in the encroachment and breakthrough of water from the aquifer. The sensitivity of water cut to drawdown was clear indication of water coning. To keep the well producing water free, initially the well was gradually choked back. The issue was further compounded by the deposition of organic materials in the long string, resulting in restrictions and choke plugging problems. Latest test results prior to the remedial job carried out on the well are presented in the table 1. As the results clearly indicate, the well was suffering from water coning issues. To ascertain continued water free production from the reservoir to maximize oil recoveries, it became necessary to address the diagnosed skin to effectively achieve higher production rates at a reduced drawdown. Well bore clean out Treatment was started with the wax clean out job. 100bbl of Toluene + Diesel were mixed for the wellbore cleanout operations. The Toluene – Diesel mixture was pumped in batches of 3 bbl, each batch circulated out by 15 bbls of NH4Cl. During the tubing cleanout operations, the well was being continuously flowed at moderate rates into the flare pit to allow for effective displacements of solids out of the wellbore. Total volume of Toluene-Diesel mixture used during the operations amounted to 100 bbl while 443 bbls of 4% NH4Cl brine were used in effectively cleaning well tubing. Acidization treatment was designed to pump the acid at different depths of open hole but unfortunately during RIH, coil tubing experience slack at 2714m so it is decided to limit maximum injection depth up to 2713m.Treatment started with the pumping of Mutual solvent based on 4% NH4Cl is used as preflush. The main acid treatment was pumped in stages comprising of live acid and diverter,
of 38bbl and 12bbl respectively. The sequence and volume of injection of each stage is presented below. Pre-Flush Main Treatment Post-Flush
4% NH4Cl Brine
71 bbl
15% HCl
190 bbl
NDA-S Diverter
48 bbl
4% NH4Cl Brine
48 bbl
Nitrogen lift off was not required due to high reservoir pressure and well started to off load. Both strings have been effectively cleaned. Well test is performed using test separator and results shows an increase of 130bbl/ day in oil production (see fig.3) while reducing drawdown has eliminated the water cut. Well tests are performed two times with a gap of two weeks which shows that water free production from the well is sustained (Table 2).
Conclusions The treatment objectives of this well include cleaning of wax in the tubing and stimulation of near well bore damage. To achieve these goals, an approach was developed, for wax cleaning toluene and diesel mixture is used while in stimulation acid and a self diverter is used, both with combination of coil tubing. Because pre and post-stimulation PLT logs were unavailable due to commercial and economic constraints, it is impossible to conclude where the actual stimulation fluid went. The success of the stimulation treatment is entirely based on pre and post well test results and production data. The following conclusions were reached regarding the treatment performance: The polymer free diverter system provides effective diversion and allowed acid to stim-
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Successful Matrix Stimulation and Wax Cleaning of a High Water Cut Oil Well
ulate damaged interval and help in effective stimulation. After treatment, an increase of 130bbl/day in oil production is observed while water cut reduces to 0% (see fig 2, 3). Wax clean out is done effectively with toluene and diesel mixture.
Acknowledgments The author would like to thank Pakistan Petroleum Limited for the permission to
publish this paper. The author also would like to thanks to Dr Fareed Siddiqui, Mr Noman Khan and Mr Sheharyar Mansur for data and support while completing this case study. Nomenclatures VLP Vertical Lift Performance GOR Gas Oil Ratio Scf/STB Cubic feet per Stock Tank Barrel BHT Bottom Hole Temperature CT Coil Tubing RIH Run In Hole PLT Production Logging Tool bbl/day barrels per day DST Drill Stem Test
References 1. Chang, F., Qu, Q. and Freniner W.: “A Noval Self-Diverting-Acid Developed for Matrix Stimulation of Carbonate Reservoirs” paper SPE 65033, presented at the 2001 SPE International Symposium on Oil Field Chemistry held in Houston, Texas, 13–16 February 2001. 2. Navarrete, R.C., Holms, B.A., McConnell, Linton, D.E.: “Emulsified Acid Enhances Well Production in High-Temperature Carbonate Formations,” paper SPE 50612 presented at the 1998 SPE European Petroleum Conference held in The Hague, The Netherlands, October 20–22. 3. Nasr-El-Din,H.A. Solares, J.R., Al-Mutairi, S.H. Mahoney, M.D.: “Field Application of Emulsified Acid- Based System to Stimulate Deep, Sour Gas Reservoirs in Saudi Arabia,” paper SPE 71693 presented at the 2001 SPE Annual Conference and Exhibition held in New Orleans, LA, 30 September to 03 October. 4. Logan, E.D., Bjomen, K.H., and Sarver, D.R.: “Foamed Diversion in the Chase Series of Hugoton Field in the Mid-Continent,” paper SPE 37432 presented at the 1997 SPE Production Operations Symposium held in Oklahoma City, OK, March 9–11. 5. Lynn, J.D. and Nasr-El-Din, H.A.: “A core Based Comparison of the Reaction Characteristics of Emulsified and in-situ Gelled Acids in Low Permeability, High Temperature, Gas Bearing Carbonates,” paper SPE 65386 presented at the 2001 SPE International Symposium on Oilfield Chemistry held in Houston, TX, February 13–16. 6. Nasr-El-Din, H.A., Taylor, K.C. and Al-Hajji, H.H.: “Propagation of Crosslinkers Used in In-Situ Gelled Acids in Carbonate Reservoirs,” paper SPE 75257 presented at the 2002 SPE Symposium on Improved Oil Recovery held in Tulsa, OK, April 13–17. 7. Safwat, M., Nasr-El-Din, H.A. Dossary, K.A., McClelland, K., Samuel, M., “Enhancement of Stimulation Treatment of Water Injection Wells Using a New Polymer-Free Diversion System,” paper SPE 78588 presented at the 2002 SPE International Symposium on Formation Damage Control, Abu Dhabi, UAE, 13–16 October 2002. 8. Saxon, A., Chariag, B., and Reda Abdel Rahman, M.: “An Effective Matrix Diversion Technique for Carbonate Formations,” paper SPE 37734 presented at the 1997 Middle East Oil Show, Bahrain, March 15- 18. 9. Robert J.A. and Crowe C.W.: “Carbonate Acidizing Design”, Reservoir stimulation Vol.3
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10. Daccord, G., Touboul, E. and Lenormand, R.: “Carbonate Acidizing Towards a Quantitative Model of the Wormholing Phenomenon,” paper SPE 16887, SPE Production Engineering (February 1989) 11. Shnaib,F. , Desouky, A.M., Mehrotra, N., Kuthubdeen, M., Rutzinger, G., Judd, T.C., and Rebello, R.P.: “Case Study of Successful Matrix Stimulation of High-Water-Cut Wells in Dubai Offshore Fields,” paper IPTC 13203 presented at International Petroleum Technology Conference, Doha, Qatar , 7–9 December 2009. 12. Zerhboub, M., Touboul, E., Ben-Naceur, K, and Thomas, R.L.: “Matrix Acidizing: A Noval Approach to Foam Diversion,” paper SPE 22854 presented at the 66th Annual Technical Conference and Exhibition held in Dallas TX, 6–9 October 1991. 13. Parlar M., Parris M.D, Jasiniki R.J, Robert J.A.: “An Experimental Study of Foam Flow Through Berea Sandstone with Applications of Foam Diversion in Matrix Acidizing”, paper SPE 29678 presented at the Western Regional meeting held in Bakersfield CA, 8–10 March 1995. 14. Al-Mutawa, M., Al-Anzi, Ravula, C., Al Jalahmah, Jemmali, M., Samuel, E., and Samuel, M.: “Field Cases of a Zero Damaging Stimulation and Diversion Fluid from the Carbonate Formations in North Kuwait,” paper SPE 80225 presented at the SPE International Symposium on Oilfield Chemistry held in Houston, Texas, U.S.A., 5–8 February 2003.
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Initiating the Employee – Employer Dialogue 15th Engineering Job Fair in Cracow Iwona Dereń The voices of visitors have died away and the expositions have become empty. It means, that The 15th Jubilee Engineering Fair is over! Similarly to previous years, the exposition astonished arrivals by its remarkable invention and afforded them a pleasant background for meetings. If to look around and see how many people took part in this event, it’s clear, that there is definitely a need and desire to make the link between the academic world and companies. This is a great start!
Before it began The idea of Engineering Job Fairs was conceived in 1997 and 1998, owing to the will to create and occasion for students and young professionals to meet with employers in an informal setting, discover exciting oppor-
tunities available in the start-up field, learn more about job, and internship opportunities offered by companies, government agencies, and non-profit organizations where students and young professionals might like to work. Career fairs give businesses and organizations a chance to present their values to prospective employees and community members. The amount of the companies during the first edition in 1999 reached 30 and approximately 500 visitors. This was a good forecast for the future of engineers and people who were looking for a job. This high level turnout clearly indicated that companies need workers from Poland. Since that time, Engineering Job Fairs organized by BEST AGH Krakow Students Association take place at the beginning of the year – in March – at Sport Hall of Wisła Kraków, located next to dormitories and buildings of AGH University.
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Iwona Dereń
Every year and every edition brings more companies, more visitors and more challenges.
Initiating the Dialogue On March 7th 2012, the city of Krakow at Sport Hall of Wisła Kraków, organized by BEST AGH Krakow Students Association, the 15th Engineering Job Fair hosted representatives of the companies, students, graduates and young professionals. Aside from science and technology-oriented companies, a number of management-oriented companies participated in the career fair. This exhibition event appeared to be a great success – it has attracted a great deal of interest from students and employers alike. Part of the purpose of the career fair was to expose graduating students to potential employers. Many of them took park in the programme of conferences, seminars and workshops. Also, they could gain more information about companies like: ABB, Cisco, EPO, Ericpol, FMC Technologies, Oracle, Valeo Autosystemy and more that featured during this event. The company Schibsted Tech Polska founded a tablet, that was a reward in one of the prize-draws. According to the voting – ABB company was chosen as the best exhibitor of the 15th Engineering Job Fairs.
Expanding Your Horizons Whether you're a student looking for an internship, a young professional looking for your first job or a seasoned engineer looking to breathe new life into your career, there are a lot of ways to go about looking for that dream internship, but few are as effective and time-worthy as a career fairs, which are a gold-mine of networking opportunities, getting profession advice or practicing job-searching skills.
Being unprepared is a recipe for failure, and failure is for tools.
Sadly, it is well known that far too many students attend career fairs completely mindlessly. Dressed like they just rolled out of bed, not prepared at all, without defined career goals and lacking any enthusiasm or self-confidence – this is the common image of some students attending job fairs. The first step to avoid this is preparing, which should be obviously done before the job fair starts. The resume is a snapshot of your entire professional life. At a career fair you’ll look like a newbie without it. However, it’s not enough to just have a resume. It needs to be tailored to perfection.
Your superficies, outer appearance is part of the impression you make on people, and it is taken as a reflection of your inner value, worthiness and qualities.
Everybody knows, that are a limited amount of internships, and a seemingly never-ending torrent of desperate students willing to sing, dance, jump, and do anything else to get them.
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Initiating the Employee – Employer Dialogue
YoungPetro at the Engineering Job Fair
found our conversations informative and useful.
Our YoungPetro Magazine was honored to have a stand during the Job Fair! It was a pleasure for us to get to know that so many people are interested in what we do. We would like to thank you all for taking the time to visit our stand during this event! We enjoyed meeting you and were glad that you had the chance to learn more about our magazine and we hope that you have also found our conversations informative and useful. As the editorial board of YoungPetro, we would like to thank you all for taking the time to visit our stand during this event! We enjoyed meeting you and were glad that you had the chance to learn more about our magazine and we hope that you have also
To Be Continued… The 15th Engineering Job Fair is over but that doesn't mean the work is finished. The days and weeks in the wake of a career fair are the most opportune time to improve your chances of being called back for an interview. Overall, the International 15th Engineering Job Fair once again confirmed its position as the important event of this kind in Kraków. So, regardless of the extent to which technology makes it easier and faster to share information between job seekers and employers, nothing replaces in-person contact for making an impression. Hopefully, next year’s edition will bring even bigger successes!
The exchange of experiences with business professionals • Proven business development concepts • Ready-made solutions for current problems • Innovative sources of additional income • Ways to look for savings • Market trends and prognosis
Building and strengthening successful business relationships • Direct contact with the most important
decision-making business world representatives • The opportunity to present your current
offer in person • Creating and strengthening your image
among the market leaders
The mosT imporTanT conference for professionals in The fuel polish secTor
www.petrotrend.pl
Media partners:
Contact the organizer: BROG Marketing, tel. 22 594 45 83 e-mail: petrotrend@brogmarketing.pl
64
̂̂Let’s Shape the Fuel Market – PetroTrend 2013! Jakub Szelkowski, Barbara Pach
The constructive discussions, an exhibition and promotion of the most important companies of the fuel sector, priceless experience – that exactly was PetroTrend Fuel Forum 2013! These event has got a prestigious position among the conferences held in the Polish fuel sector for many years! The 13th edition of this fantastic event was held on 14th March at the Hyatt Regency Hotel in Warsaw. The whole meeting was divided into four thematic parts. It made it full of discussions and the speeches called all the participants for reflection.
But panel discussion engaging as many professionals is so important to exchange ideas.
Stop at the fuel station and stay there longer! The next part of the conference was started by Dominika Odejewska, the owner of the Odejewscy Center–the fuel station with many facilities for travelers. She was talking about her
Discussion – first step to introducing changes… First part was started with the speech of Szymon Araszkiewicz, the director of consulting, Information Market/e-petrol.pl, who tried to face the problems in the Polish Fuel Market. He started with the analysis of last two years, which caused a heated discussion. Discussants brought up the issue of low margins due to high charges to the State (VAT, excise tax, fuel charge), as well as the emergence of the so-called in Poland "gray zone" of individuals and companies illegally dealing in fuel. It’s so difficult to solve problems like these…
family’s business with so much passion. They have given an example how to make a great business. Dominika revealed how to deal with crisis managing the fuel station by providing full-service center for travelers! Apart from fuel station the Odejewscy Center is also:
Jakub Szelkowski, Barbara Pach
car wash, vulcanization’s center, restaurant, banquet halls, mini-ZOO, dinosaur park, children's playground and many others… They changed the fuel station from a come-refuelpay-leave place to a travelers friendly center for everyone to stay in longer... Moreover, she emphasized in her speech the great importance of reducing costs by investing in renewable energy sources, reduce energy consumption and water. That is exactly the key to success!
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Polish Fuel Market and it is developing so fast nowadays. Raised in the block topics include: the situation of independent operators on the fuel market, working with corporations franchise, partnership, progress the consolidation of the independent stations, small stations problems – how to compete with the giants and survive.
It’s time for freshness!
Let’s debate with the representatives and the most influential companies!
It would seem that apart from Neste Oil there is no place for other players in Polish Market…nothing further from the truth!–told Michał Szymajda, head of network development at HUZAR during the third part of PetroTrend Fuel Forum. The network of Polish Fuel Stations HUZAR is something new in
The last and the most exciting part of PetroTrend 2013 was provided by the speeches of representatives of key companies in Poland, among others Bogdan Kucharski CEO of BP in Poland, Krzysztof Starzec director of fuel sector Statoil Fuel & Retail Poland, Paweł Maślakiewicz director of sales management
winter/spring / 2013
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Let’s Shape the Fuel Market – PetroTrend 2013!
in LOTOS Group and Marek Balawajder, executive director of retail sales of PKN ORLEN. The discussion was long but very construc-
tive. It was about state policy towards the oil sector, how to adapt to the new requirements and how to introduce regulatory changes.
The Fuel Station of 2013 At the end of PetroTrend Fuel Forum 2013 was announced the results of the second edition of The Fuel Station of the year 2013 contest. The winner of the contest was chosen from the finalists in several categories and it was BP Port Świecko 39 in Poland.
Presence in this prestigious group of key fuel companies from the fuel market gave the chance to exchange experiences and opinions but first of all – it gave the chance to gain new or maintain current business relations.
We could not miss such an important event, that is why our magazine was a Media Partner of PetroTrend 2013! It was great pleasure to be part of the event, we are looking forward to the next edition of PetroTrend Fuel Forum. See you again in 2014!
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WInTer / SPrIng / 2013
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International Student International Student Petroleum Congress Petroleum Congress & Career Expo & Career Expo
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