O&G MENA 5

SPECIAL REPORTS Yemen’s energy outlook Untapped potential in Iraq

www.ngoilgasmena.com • Q2 2010

REDEFINING REFINING With Dr Eion Turnbull, Deputy CEO of Bapco

FIELD OF DREAMS KOC’s exploration chief, Khalid Al-Sumaiti, outlines the company’s 2030 vision

BRIGHT SPARK Gerald Schotman, CTO of Shell, on the oil giant’s innovation strategy

BAHRAIN’S

OPPORTUNITY Minister of Oil and Gas Affairs HE Dr Abdul-Hussain Ali Mirza on why the future is bright for his country’s energy sector

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ED NOTE NGO&G MENA 5_feb10 12/03/2010 16:58 Page 7

FROM THE EDITOR 7

Energy struggles Why the world’s oil hotspots are also the most volatile countries in the region.

W

here there’s oil, there is conflict. Some of the world’s most hostile territories contain the greatest oil reserves, deep under the ground on which the battles are played out.

Terrorist activity, dictatorial leaderships and crippling poverty often characterise the very countries that hold the key to the world’s future energy supplies. Indeed it is for this very reason that these territories are so often the subject of brutal power struggles and tribal conflicts. Nothing sparks hostility more than the battle for possession of the world’s most precious resource.

Take Iran for instance, a country with a volatile political situation upon which the US has imposed strict trade sanctions amidst concern over its uranium enrichment programme.

According to the US Energy Information Administration bureau, it holds around 10 percent of the world’s total oil reserves: an estimated

137.6 billion barrels of proven oil reserves as of January 2010. It is OPEC’s second largest producer after Saudi Arabia and produced a massive 3.8 million barrels of crude oil a day in 2009.

In this issue we report on two of the most volatile oil producing countries in the Middle East – Iraq and Yemen. The latter is the Arabian Peninsula’s most impoverished nation and relies almost completely on oil production for its economic survival. Terrorism has dogged government efforts to increase production, but despite a series of high profile strikes by Yemen-trained terrorists and repeated threats to attack oil facilities, major international oil companies, including Total, are investing in the country’s energy sector. Total has poured US$45 billion in the Yemen LNG gas plant, which has the capacity to produce up to 6.7 million tonnes a year of LNG and could generate a revenue of US$50 billion by 2028. Meanwhile, US-based Hunt Oil and Austria’s OMV are also engaged in exploration activity there.

The military occupation of Iraq and its ongoing struggles with insurgency and political instability have not stemmed the flow of billions of petro-dollars from the world’s biggest oil companies eager to cash in on its vast oil and gas reserves.

As we report in this issue’s article on the country’s energy sector, only around a quarter of the country’s known fields have been tapped for oil so far.

But with the likes of BP, CNPC, LUKOIL and ExxonMobil having won contracts to operate there, analysts predict that around triple the outdated reserves figure of 115 billion barrels could be discovered. While the political situations in these countries shift constantly, oil remains the constant that will ensure the conflict and the international involvement in these region intensifies as world oil demand increases.

“The global recession has impacted

“Our philosophy is that when we get

“There is a huge capacity for innova-

the worldwide demand for petroleum

good people we need to make it attrac-

tion outside and we would be very ill-

product and the corollary of this is a

tive for them to stay in Kuwait, have

advised to put the blinkers on and

reduction in refinery margins. Hence,

good facilities and a good working envi-

ignore this potential source of good

the recession has definitely reduced

ronment. However, we don’t have much

ideas. We already have multiple part-

our earnings”

flexibility on salary”

ners in collaborative research projects,

Dr Abdul-Hussain Ali Mirza, Minister

Khalid Al-Sumaiti, Deputy Managing

from industry to academia”

of Oil & Gas Affairs, Bahrain

Director of Exploration and Production

Gerald Schotman, Chief Technology

(page 26)

Development, Kuwait Oil Company

Officer, Shell

(page 44)

(page 102)

Diana Milne Editor

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CONTENTS 9

44

Land of opportunity HE Dr Abdul-Hussain Ali Mirza, Minister of Oil and Gas Affairs in Bahrain, speaks exclusively to O&G about what the future holds for his country’s energy sector

Field of dreams Kuwait Oil Company (KOC) faces both technology and staffing challenges as it bids to ramp up output. This is the responsibility of Khalid Al-Sumaiti, Deputy Managing Director of Exploration and Production Development, who explains his strategy in this interview

26 Redefining refining As oil refineries encounter one of the toughest periods in their history, Bapco’s deputy CEO Dr Eion Turnbull reveals what the company is doing to stay one step ahead of the competition

78 Untapped potential Can Iraq’s leaders unlock the country’s oil riches and put the country on the road to recovery?

32

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CONTENTS 10

124

Safety success

96

On the edge

ASK THE EXPERT 68 Nicholas Newman, Alfa Laval 84 Aykut Selcuk, Armada Offshore 106 Marc Hockfield & Hamish Strang, Senergy 116 Graeme Eastwood, Fugro-Jason

Falih on the state of play in the global oil and gas industry

66 Success story An overview of Occidental Petroleum’s achievements in the MENA region

70 A chemical reaction

How Qatar is morphing into a natural gas superpower

Ali Al-Naimi, Minister of Petroleum and Mineral Resources in Saudi Arabia, gives his perspective on the future of the Kingdom's refining industry

50 The energy challenge

88 Rebirth of Rumaila

Matthias Bichsel discusses how Shell is looking to meet the world’s energy needs in economically, socially and environmentally responsible ways

We report on the Rumaila oilfield redevelopment project, the first long-term oil contract of the post-Saddam era

40 Turn up the gas

96 On the edge 60 Facing up to reality Saudi Aramco President and CEO Khalid Al-

114

Improving oil and gas collaboration

What the future holds for Yemen as terrorism threatens its oil and gas industry

INDUSTRY INSIGHT 48 Graeme Simpson, RPS Industrial 75 John Sanins, Bentley Systems 86 David Baley, Petrowell 94 Daniel Hitzman, iGeo-Microbial Technologies 122 Jaakko Uotila, Frictape Net Ltd

EXECUTIVE INTERVIEWs 56 Arshad Matin, Seismic MicroTechnology 64 Jan Strom, First Crude Oil 76 Espen Norheim, i-TEC 110 Gerry Connard, Geosoft 134 Richard Norsworthy, Polyguard Products

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CONTENTS 12

104 Making connections

118 In safe hands

130 Rust never sleeps

Shell’s Chief Technology Officer Gerald Schotman lifts the lid on the oil giant’s IT strategy and what makes him tick

HSE issues come under the spotlight with Yassin Darwish, safety chief at Dana Gas Egypt

Mark Byerly explains why inspecting pipelines is vital in the battle with corrosion

108 The magic number

124 Safety success

IDC’s Catherine Madden on the three essentials for developing the next generation digital oilfield

Hans Jorn Johansen examines the safety improvements the industry has seen over the past two decades

114 Improving oil and gas collaboration

128 Engineering solutions

136 Iran Rising How Iran is preparing itself to become a major player in the global natural gas business despite economic sanctions

138 Cracking the corrosion code

According to a new report, oil and gas professionals view social media as important for productivity and collaboration

Dubai Petroleum’s Yusuf Al-Taher outlines the engineering challenges he and his team are working to solve

With PPSA members Thomas Beuker, Bryce Brown and Mohammed Jaarah

94

A scientific approach

128

Engineering solutions

Making connections

102

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NG O&G MENA Summit 2010

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A Controlled, Professional and Focused Environment The NG O&G Summit is an opportunity to debate, benchmark and learn from other industry leaders.

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INVESTING IN THE FUTURE Across the Middle East IOCs are investing heavily in Liquid Natural Gas but as more facilities come online, will demand continue to outstrip supply?

Ask any Middle East based interor establishing new plants. And national oil company exploration activities what projects are on to discover new In2010 their agenda for LNG using enconsumption world2010 and increased hanced oil recovwide will grow by LNG production is ery techniques certain to crop up. to access deep compared with Across the region reserves are well 7.5% in 2009 companies are investunderway. These coming billions of dollars in panies have good reason upgrading existing LNG facilities to invest in the production of a

17%

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UPFRONT 17 fuel for which demand is set to in the LNG market, other soar worldwide. Analysts predict countries are fast getting in on that demand for the fuel will have the act. Bahrain is investing bilrisen by 67 percent by 2030 and lions of dollars in deep gas that it currently provides 23 perexploration with hopes of cent of all energy consumed in establishing an LNG plant, the world. According to the meanwhile Kuwait Oil International Energy Agency, gas Company has recently signed a consumption is projected to rise in five year service contract with most regions over the next three Royal Dutch Shell to develop decades until 2030 with demand pure gas fields in its northern driven chiefly by increased use of regions. It plans to increased power generators. The only region output from the gas fields to where a slight decline in demand is one billion cubic feet a day forecast by 2030 is the US. from about 140 million cubic Consumption worldwide will grow feet a day currently. by 17 percent in 2010 compared However, while investing with 7.5 percent in 2009. in these facilities is a naturCurrently over half al response to predicPlans to of the world’s gas tions of increase increase output reserves are located demand, some anfrom the gas in Russia, Iran alysts warn that fields to and Qatar, with as increasing the latter boasting number of LNG cubic feet a the world’s biggest facilities come onday LNG processing units. line, there is a danger Qatar’s aim, through statethat supply could begin to run Qatargas and RasGas, is to outstrip demand. Indeed a report boost LNG capacity to 77 million by analysts Sanford C. Bernstein tonnes by the end of this year – & Co warns that global LNG supwith output currently at 54 milplies will exceed demand for the lion tonnes per year. To reach second year running in 2010 this target it will start production warning: “Much like in 2009, at two giant new LNG plants, supply increases are expected to which will primarily serve the be ahead of demand growth.” It LNG hungry markets of China attributes the imbalance to reand India. The country signed duced demand for LNG from deals last year to sell millions of utilities in Japan and South tonnes of LNG to China and earKorea due to the global receslier this year the Indian oil minission. It states, however, that ter Marla Deora met the Qatari conditions will improve in 2011 oil minister Abdullah al Attiyah when LNG prices are expected with a view to seeking additional to rise markedly led by increased supplies. Qatargas’ latest LNG demand from the UK, China, production facility, train 6, will India and Turkey. “Looking furhave enough capacity to produce ther ahead we continue to be7.8 million tonnes of LNG per lieve that global gas pricing will year for export. Meanwhile train strengthen in the 2011-15 peri7, due to start production in od.” For now however ME comSeptember, will have equal capanies play a waiting game and pacity. While Qatar continues to hope heavy investments in LNG outperform its GCC neighbours will one day pay off.

NEWS IN PICTURES

More than two months after a deadline for UN sanctions against Iran passed, attention is focusing on calls for unilateral measures against the nation’s oil and gas industry

1 billion

Shell has been forced to close down two gas plants feeding Nigeria's power stations in order to carry out repairs on a sabotaged supply pipeline in the volatile oil-producing region

OPEC Secretary General Abdallah El-Badri says talks have begun between the oil cartel and Iraq about bringing the country back into the oil-producing quota system next year

UK oil giant BP has announced that it has reached a deal to acquire the US firm Devon Energy's assets in Brazil, Azerbaijan, and the US Gulf of Mexico for US$7 billion

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UPFRONT 18

ABU DHABI

QATAR

Takreer, otherwise known as the Abu Dhabi Oil Refinery Company has signed contracts worth US$9.6 billion to expand its Ruwais plant. It has signed contracts with the SK Engineering and Construction Company, Samsung Engineering Company and Daweoo Engineering and Construction Company who will be carrying out the work. It hopes to double capacity at the refinery from its current output of 400,000 barrels a day. The Ruwais expansion will be completed by 2013. Samsung Engineering Company revealed in November that its contract to work on the site will be worth US$1.17billion.

RasGas has started output of liquefied natural gas from a massive new production facility. Qatar currently has the world's third largest supplies of gas reserves and it hopes its increased output will help to expand its economy by 16 percent this year. The RasGas train 7 facility has the capacity to produce an additional 7.8 million tonnes a year. The gas will be exported on specially designed tankers that are the largest in the world. Exxon Mobil owns a 30 percent stake in the plant while the government of Qatar owns the remaining share. The gas is produced from the North Field, which is the largest pure gas field in the world.

KUWAIT Kuwait Oil Company has signed a five year service contract with Shell, which will see the Dutch oil giant develop pure gas fields in the north of the country. Demand for gas in Kuwait has now outstripped supply, forcing the country to import LNG. The contract with Shell will help to meet Kuwait's target to increase output from the fields to one billion cubic feet a day. Currently output is around 140 million cubic feet a day. More gas output from pure fields would help meet demand for clean energy for power generation, oil industry operations and petrochemical plants.

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UPFRONT 19

DUBAI

SAUDI ARABIA

Dubai based ENOC is to hold back on further acquisitions this year and will focus on existing operations instead. The information was revealed by the firm's Chief Financial Officer Petri Pentti during a call to the Reuters news agency. He also revealed to Reuters that at the end of 2009, the company held assets worth US$6.5 billion. "This year the focus will be on the vertical integration of the business and upgrading our refineries and so far there are no plans for any investments," Pentti said. The decision follows ENOC's failed bid to acquire the assets of Dragon Oil last year. The company plans to raise capacity from its Jebel Ali refinery from 70,000 to 120, 000 barrels a day having spent US$850 million dollars overhauling the plant.

Exports of crude oil from Saudi Arabia to India are to double following an announcement by the oil minister Ali Al Naimi. He has agreed to raise exports to India to 40 million tons a year or around 70,000 barrels a day. The announcement follows a visit by the Indian Prime Minister Manmohan Singh, which cemented the kingdom’s role as the biggest crude supplier to India. India is currently looking to increase supply for three new refinery projects, at Paradip, Bhatinda and Bina. Increasing imports from Saudi Arabia would bring India’s crude intake from the Arabian Gulf country to about 866,000 barrels of oil a day.

Work on Saudi Arabia's Jubail oil refinery is to start in late 2013, rather than in March that year as previously stated. The plant is a joint venture between Saudi Aramco and Total and will produce around 400,000 barrels a day. Dawood Al Dawood, Vice President of marketing and supply, Saudi Aramco, announced that the plant would be delayed at an industry conference. The plant will cost US$12billion to build and will play a big part in increasing Saudi Arabia's domestic refining capacity.

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UPFRONT 20

FAIL SAFE HYDROGEN SULPHUR DETECTION ble light but block light of specifOver recent years there has ic wavelengths. The interaction been a marked shift to the use between absorption and waveof optical products for the delength generates a profile or ‘fintection of methane leaks in gerprint’ for each gas molecule; safety related applications. the Beer-Lambert law defining Market research has shown the absorption physics from that the motives behind this which a gas concentration can be move are: no unrevealed quantified. Methane detection sources of failure, increased has been achieved due to the availability and improved likestrong absorption of its hylihood of detection. drocarbon (H-C) Hydrogen sulcomponent bond phide (H2S) has Hydrogen sulphide (H2S) has and the comone of the most one of the most readily mercial availreadily identiability of IR fiable odours sources and filknown to the odours known to the petrochemical ters. It should petrochemical and waterwaste be noted that and waste-water industries these devices are reindustries. The faally hydrocarbon, not miliar ‘rotten eggs’ smell methane detectors. is detectable to the human olTraditional IR sources profactory system at concentravide a wide band of light that in tions below one part per essence ‘wash out’ some absorpmillion (ppm). Hydrogen sultion lines of a given gas species; a phide is both toxic and flamnew approach was therefore needmable; research has shown ed to improve specificity. Intensive that long-term exposure to research has led us to develop a concentrations above 1 ppm technique using a single tuneable can irreparably damage laser diode source coupled with the sense of smell, whilst advanced software algorithms to higher concentrations can pinpoint specific ‘wavenumber’ prove fatal. where there is little or no interferIt is known that gases and ence from other gases. vapours are transparent to visi-

identifiable

For more information vistit www.simtronics.eu

FROM THE VAULT Back in issue three of O&G we caught up with DR SHORKRI GHANEM, Chairman of National Oil Company in Libya. In this exclusive interview he revealed how his energy sector is set to be become a giant on the world stage and the role IOCs play since sanctions were lifted. “We are inviting IOCs because of their massive financial ability which allows them to take risks with exploration,” he explained.

“We also need them for their technology and good management practices.”

Go to www.ngoilgasmena.com to read more

TRANSPARENCY PAYS

market volatility.

The report also highlighted An official report by the the need for increased investment Riyadh-based International in the industry over coming years Energy Forum (IEF), which as energy demands increase due to population growth and groups nearly 100 oil proeconomic development ducers and conin China, India and sumers, states Global the Middle East. that most of investment of Estimates from the challenges the International facing the oil Energy Agency and gas induswill be required by 2030 say that global intry could be vestment of $26 triltackled through lion will be required to greater transparency. meet projected global energy deThe IEF is calling for increased dialogue between energy pro- mand by 2030. Of this investment ducers and consumers with a $250bn will be required in the oil view to ending the persistent and gas sector alone.

$26 trillion

Simtronics GD1 Toxic open path gas detector

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UPFRONT

GREAT DISCOVERIES

21

LIFELINE Dana Gas, the largest regional private sector natural gas company in the Middle East, has announced two gas discoveries in the Nile Delta, Egypt.

The first discovery was at ‘El Panseiya-1’ in the West El Manzala Concession and the second was ‘South Faraskour-1’, also in the West El Manzala Concession. Both discoveries are expected to be tied in to the Company’s nearby El Wastani gas processing plant by the end of 2010.

Mr Ahmed Al Arbeed, Dana Gas CEO, said: “Our team in Egypt continues to deliver tremendous results.

We are delighted that these two exploration wells have been successful. They build upon Dana Gas Egypt’s outstanding 2009 achievement of eight discoveries from twelve exploration wells, which resulted in a 40 percent increase in proved plus probable (2P) reserves to 132 million barrels of oil equivalent at the end of the 2009.”

FAST FACT

Dragon Oil is to invest

US$870 million in oil and gas projects by 2012 to boost production

War-torn Iraq is to receive a US$3.6 billion loan by the International Monetary Fund (IMF) – the biggest to the country so far. The IMF executive board approved the two-year so-called Stand-By Arrangement for Iraq “to cover the country’s balance of payments needs” after the economy was hit hard by falling oil prices in 2009, the Washingtonbased institution said. The money will be used to rebuild Iraq’s battered infrastructure and US$455 million will be made immediately available to deal with the most urgent issues.

Iraq has received similar loans from the IMF in the past, with the condition of removing subsidies from manufacturers and farmers.

Declining oil prices last year left Iraq dependent on oil for almost 90 percent of its

revenue, with a public deficit of 20 percent of economic output, and it faces a financing gap of close to US$5 billion until the end of 2011, said Ron van Rooden, IMF mission chief in Iraq, in a conference call with reporters. Since oil prices started picking up Iraq fared slightly better and the nation's financial needs have been trimmed slightly.

Zawya reports that the financial shortfall in Iraq's budget comes at a difficult time as its 29 million people struggle to emerge from a brutal sectarian conflict triggered by the 2003 US-led invasion. The new IMF loan follows a 15-month programme supported by a StandBy Arrangement at the time valued at US$744 million approved on December 20, 2007, which expired on March 18, 2009. www.busmanagementme.com/news/iraq-getbiggest-ever-IMF-loan/

FIRST H&S DATABASE TO BE DEVELOPED Warwick International Computing Systems has been given the honour of developing the UK’s first national Occupational Health database for the construction industry by Constructing Better Health (CBH).

Warwick was chosen due to CBH’s requirements being very closely modelled on its framework of integrated OH and H&S Management Software Modules. The database also utilises unique web-based systems e-OPAS and e-SAFETY. Warwick has continued to develop solutions to ensure they address the ever-changing needs of their customers, be it in light of new regulations or new best practice procedures such as OHSAS 18001. All the software can be customer configured as we do not believe one size fits all and therefore all the installed solutions are tailored so they can integrate with established protocols and procedures.

e-OPAS and e-Safety are part of the GeNOHSIS suite of Occupational Health and Health and Safety Management Software. They have the ability to be integrated as the company firmly believes in the increased benefits of a unified approach to the assessment and management of workplace risk. Combined with efficient record keeping and analysis, organisations can effectively reduce the risk posed to employees.

The solutions, e-OPAS and e-Safety, allow organisations to identify potential hazards before they are allowed to pose a significant health risk to personnel and introduce targeted proactive measures. In addition, the solutions can aid in the reduction of workplace accidents, reduce loss time and encourage a more motivated, healthier and productive workforce.

For more information, see the advert in this publication, email enquires@warwickicsystems.com or visit www.warwickicsystems.com

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UPFRONT 22

GCC member states in particular will benefit from the global uptick in credit market con2010 looks like it could be a good year for the ditions last year, with ambitious infrastructure MENA region as the economy is likely to be projects continuing to be churned out across the given a welcome boost from higher oil prices, region. “GCC governments will maintain relaa stronger global economy and loose domtively high levels of public spending and investestic policy conditions, according to a ment,” an EIE analyst stated. “This new report by the Economic will, in turn, support non-oilIntelligence Unit (EIU). OPEC producing countries in Mena continues to exercise restraint that benefit from regional oilper barrel is good, prices above this are but this may not last long as related liquidity in the form of better,however ,triple oil production is expected to inward investment, tourism digit prices would pick up throughout this year demand and workers' remitstifle global recovery and grown even stronger in 2011, tances.” helped massively by the consistent Saudi Arabia, the largest of the government spending in major oil-producing Arab markets, is forecast to enjoy the strongest countries, according to the report. “US$50-70 growth across 2010-11 at 3.4 percent. For other per barrel is good, prices above this are better. countries in the region, Gokkent said Kuwait [However], triple digit prices would stifle globwill likely see 3.1 percent real GDP growth, al recovery. A low price would mean greater Qatar 15.8 percent, Oman 2.64 percent and for prioritisation/scrutiny of projects and adjustBahrain the expected real GDP should be 2.2 ment in expenditure levels,” Giyas Gokkent, percent. The EIU concluded: “Having stagnated Group Chief Economist of National Bank of in 2009, regional economic growth is expected to Abu Dhabi (NBAD), rebound strongly to average 4.5 percent in 2010told Emirates 2011, although this is still lower than the 6.8 Business. percent average annual growth rate in 2005-2007.”

A POSITIVE OUTLOOK

US$50-70

SHELL ENDS GAS SALES Netherlands-based oil giant Royal Dutch Shell says it is no longer selling gasoline to Iran, beginning the latest in a growing number of oil firms to halt supplies to the Islamic Republic.

Other large western firms that have stopped fuel sales to Tehran include Switzerland's Glencore and Geneva-based Vitol.

Executives and traders say oil companies are moving away from Iran for political reasons.

US lawmakers are working on legislation that backs unilateral sanctions on companies that make fuel deals with Iran. Lawmakers hope the sanctions will persuade Iran to stop expanding its nuclear programme. Iran is one of the world's largest oil exporters but still relies on imports for about 40 percent of its refined product.

This dependence is largely due to decades of sanctions that have hindered Iran's refining capacity. Iran spends billions of dollars each year on oil imports and energy subsidies for citizens.

FAST FACT

SUN IN PLACE OF OIL The Saudi authorities have vowed to use the sun instead of oil to desalinize water. Up to now, more than 28 desalination plants scattered around the Kingdom have had to rely on fossil fuel, most notably fuel oil, to provide power to run the equipment used to extract salt and other minerals from sea water. At the start of February the UAE Top News media site reported that the Kingdom is now planning to build solar-based desalination plants in order

to save on energy costs, as well as be in tune with new environmental polices. The move could be perceived as a ploy to secure membership in the International Renewable Energy Agency, otherwise known as IRENA. Plans for a high-speed rail network to carry pilgrims to and from the annual Hajj pilgrimage in the Holy Cities of Mecca and Medina also signify the Kingdom's willingness to become more environmentally friendly. www.busmanagementme.com/news/saudi-arabiasolar-energy/

Middle East oil demand will grow by

5% in 2010, according to the International Energy Agency

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TOP 10 OIL CONSUMERS

PROVED RESERVES AT THE END OF 2008

The world uses up almost 82 million barrels of oil every day, or 30 billion barrels per year, and consumption is rising by the day with economies like India and China growing at breakneck speed.

1 2 3 4 5

6

7 8 9 10

USA 20,698 (23.90% of total) CHINA 7855 (9.30%) Japan 5051 (5.80%) India 2748 (3.30%) Russian Federation 2699 (3.20%) Germany 2393 (2.80%) South Korea 2371 (2.70%) Canada 2303 (2.60%) Saudi Arabia 2154 (2.50%) France 1919 (2.30%)

HIGH HOPES

DEFENCE PACT SIGNED

Iranian Defence Minister Ahmad Vahidi was in Qatar recently to sign what Tehran says is a defence cooperation accord with its smaller neighbour. Qatar also houses a major US military base, as the small Gulf state plays a delicate balancing act between east and west.

Vahidi, who rarely travels abroad, attended the signing ceremony in Doha. He says Iran and Qatar share mutually positive relations in all fields, and especially in important regional defence issues. He said they saw eye to eye after extensive consultations and that constructive cooperation between both countries was among the chief reasons for strengthening ties. He added Iran and Qatar’s good relations are an example for other states in the region. Vahidi's visit to Qatar coincided with a visit to Iran by a Qatari delegation pursuing expanded cooperation in oil and gas production.

The 2010 outlook is optimistic for the oil and gas industry according to the latest quarterly outlook from Ernst & Young’s Global Oil and Gas Center.

Given the continuing demand for oil, the sector is likely to fare better than most in the coming year.

David Barringer, Ernst & Young’s Oil & Gas Leader in the Middle East, believes that more consolidation can be expected within the sector as larger companies will inevitably be taking advantage of strategic opportunities.

Andy Brogan, Ernst & Young's global oil and gas transaction advisory leader, said: “The positive trends that we have seen in recent months are likely to continue into 2010 and the outlook for oil and gas transactions is healthy in upstream and oilfield services. In the downstream sub-sector, over-capacity in some regions is likely to drive a longer period of uncertainty and transactional challenges.

But as 2009 has demonstrated, one person’s challenge represents another’s opportunity.”

Source: www.voanews.com

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UPFRONT 24 GEORGE KIRKLAND, EXECUTIVE VICE PRESIDENT FOR CHEVRON, ON THE MAIN DRIVERS REDEFINING THE WORLD’S 21ST CENTURY ENERGY EQUATION. Chevron believes in natural gas. We have 150 trillion cubic feet of un-risked gas resources located throughout the world. Our holdings in the AsiaPacific region are the largest in our competitor group. Natural gas will clearly have a larger role in our future. And today our industry is gripped by tough, complex challenges; sustaining long-term growth and the supply of new gas to market while managing investments in the short term.

The recession has adversely impacted financing and cash flows and project development costs remain high. We’re not just dealing with the effects of a recession, however. We’re confronted by other, ongoing challenges, such as geopolitics and the reality of making final investment decisions while in a high cost environment.

We need to invest for the long-term, to ensure there’s sufficient energy available to grow the world’s economies. Without continued investment, natural gas will simply not be available to meet demand and drive economic growth.

Investing in long-term projects must always be guided by transparency, predictability and discipline. Stable, predictable and reasonable terms are needed to ensure that investment continues to flow.

A fundamental area we need to focus on is superior project execution. We must efficiently and cost-effectively deliver on projects that fulfil our commitments to host governments and buyers.

That means building projects in a safe, reliable, economic and environmentally responsible manner.

To be successful, our industry must be proficient at managing large, complex projects with multiple partners in challenging environments.

Our investments create opportunities for local communities. Chevron’s approach to community engagement is strategic. We target key areas such as job creation, healthcare, education and training. All of those contribute to building human capacity and a healthy growing society.

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UPFRONT 25

FAILING PIRATES

The success rate of Somali pirates operating in the Gulf of Aden is dropping, according to a report published in the Los Angeles Times. The report, which was written by the newspaper’s Gulf correspondent, claimed the pirates, who launch attacks off the coast of Yemen, had a 22 percent success rate last year compared to 34 percent in 2008 and 63 percent in 2007.

Despite the pirates having launched 198 attacks on ships last year, only 44 of them were successful, compared to 42 successful attacks out of 122 in 2008. The reports attributes this falling success rate to the defensive actions taken by shipping companies, including

the removal of onboard ladders, and the use of fire hoses and zigzag methods of navigations to confuse pirates. This backs up a report by Frost and Sullivan last year that in 2009 the Middle East spent US$7.9 million on seaport security with this figure expected to rise to US$11.6 million by 2016. “Rising terrorism and upcoming new ports are stimulating seaport authorities to spend more on security.

Efficient security systems will need to be procured to protect seaports in the region… Security outlays will continue to rise in the wake of proliferating terrorism and piracy,” said YS Shahisdhar, country director for South Asia, the Middle East and North Africa at Frost and Sullivan.

Despite the fact that there were more failed attacks by pirates last year, however, shipping companies were forced to pay out US$48.4 million in ransom payments because of the attacks.

COMPANY INDEX Q2 2010 Companies in this issue are indexed to the first page of the article in which each is mentioned.

AGR Petroleum 112, 113 Akkad 88 Alfa Lavel 68, 69 American Chamber of Commerce in Iraq 76 Armada Offshore 84, 85 Asry Offshore Services 37 Baker Hughes 58, 59 Baker Hughes 88 Bapco 32 Basra Petroleum Co. 88 Bentley Systems 11, 75 BMS Da Vinci AS 82 BP 88 Building Technology Trading Contracting 80 Carbovac 8 Cisco 100 CNPC 88 Cudd Energy 73, IBC Danagas 118 Dassault Systems 91 EMC 93 Eutelast 103 First Crude LTD 64, 65, OBC Frictape Net 122, 123 Furgo-Jason 116, 117 Gazprom 96 Geodis Wilson 105 Geo-Microbal Technologies Inc. 6, 94

Geosoft 110, 111 Global Energy Services 63 Gobal Centre for Energy Studies 76 Halliburton 88 Hunt oil 96 I-TEC 76, 77 IDC 108 IHS Global Insight 76, 96 Inmarsat 2 Iraq Drilling Company 88 Jesco 38 KBC IFC Kuwait Oil Company 44 Magnatech Intetnatonal 131 Masdar 32 Meet The Boss 135 Metastorm 4 Mubadala 26 Neptune Oceanographics 133 Oil Search 96 OMV 96 Pajak Engineering 43 Petroservices 13 Petrowell 86, 87 Polyguard 134 PPSA 138 Promasmexico 46 Reuters 96

Rosscor International BV 129 RPS Industrial 48, 49 Rumaila Field Operating Organization 88 Saudi Aramco 60 Schlumberger 88 Senergy Software 106, 107 Senscient 121 Shell 50, 78 Simtronics 20,125 SMT 56, 57, 102 South Oil Company 88 Sparrow Offshore Services 31 SPSE 139 State Oil Marketing Organisation 88 Stork Asset Management 119 Tatweer 26 Total 96 TRE Europe 15 Warwich Systems 21, 127 Weatherford 88

GOING GREEN If there are two things the Middle East has plenty of, it’s sunlight and oil. The region’s exploitation of the latter is well known and is the reason it has so much economic promise and is turning out some of the world’s most expensive and outrageous infrastructure projects. But as pressure mounts on the world’s largest oil producers and exporters to diversify away from dwindling fossil fuels, nations like Saudi Arabia must start to shift their energy focus in order to stay among the big players in the globe’s economic future. Saudi Arabia is perhaps one of the Gulf states taking the biggest steps in sustainable, green policies after looking to enter the world of solar energy with the launch of the first of a three-stage solar power initiative.

COVER STORY

LAND OF As the most powerful figure in Bahrain’s oil and gas sector, the Minister of Oil and Gas Affairs he dr abdul-hussain ali mirza holds the key to one of the world’s most profitable refining industries.

In this exclusive interview he tells Diana Milne about his hopes for the future.

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hen Dr Abdul-Hussain Ali Mirza started out as a fresh-faced Bapco trainee after leaving school, he never dreamt of one day becoming the most powerful figure in the country’s oil and gas industry. Today he is charged with overseeing the whole of Bahrain’s energy remit, at a time when country is undertaking a dramatic overhaul of its oil and gas industry. Formerly a relative backwater in the GCC oil and gas sector, Bahrain is currently experiencing a flurry of activity by major international oil companies following the allocating of four off shore exploration and production blocks last year. Meanwhile, efforts are underway to tap into the country’s natural gas reserves and to develop technology that will breath new life into the ageing Bahrain field.

Describing his spectacular climb to the top, the man in charge of these projects says: “I worked at Bapco for 40 years, starting off as a trainee before ending up as Chief Executive. During that period the company was kind enough to sponsor my higher education in London. Then I had to go through various positions, climbing up the ladder of the organisation. So I have been General Manager of Administration, General Manager of Services and of Finance and Legal Affairs, Deputy Chief Executive and Chief Executive. I was appointed in 2002 by his Majesty the King as a Minister of State and in 2004 I was made Minister of Cabinet affairs.”

Leading change Ali Mirza became Minister of Oil and Gas Affairs in 2005. Then, following the issuing of political, social and economic reforms by the King of Bahrain, the National Oil and Gas Authority was formed, with Ali Mirza as Chairman. Since his appointment, he has been instrumental in encouraging investment by IOCs in Bahrain’s oil sector – an achievement he describes as his proudest to date: “The main thing I have brought about is a paradigm shift in the oil and gas sector. There are lots of activities going on now in the sector. We have offered all our offshore blocks for exploration to the interna-

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tional oil companies and they are working on it now. Cooperation with international oil and gas companies based in other countries is seen by the political leadership of Bahrain, and the National Oil and Gas Authority (NOGA), to be vital to the future of the industry in Bahrain. International oil companies are the enablers for us to develop our natural resources such that the citizens of Bahrain can collectively benefit in terms of standards of living, employment and well-being.”

In addition to the major upstream projects underway at Bahrain’s four offshore blocks by IOCs, the country is also awaiting the completion of a major overhaul of the main pipeline, which transports crude oil from Saudi Arabia to Bahrain’s refi neries. Th is will enable Bahrain to achieve one of its key objectives – a plan to pour billions of dollars into the production of high quality gasoline and aviation fuels. “With respect to the new pipeline, the FEED study is ready to start while we await approvals for the onshore route of the pipeline. Th is project is part of our vision to create a refi nery that is a world leader and extremely competitive,” says Ali Mirza.

Maximising resources

tion, Tatweer will implement a drilling programme to increase the nonassociated gas production so that the planned increases in power and water requirement are met. Now one might ask how important is this to Bahrain, my answer is that the contribution to the national economy will be enormous,” says Ali Mirza.

Another activity upon which high hopes are being pinned in terms of its potential contribution to the Bahraini economy is the exploration of Bahrain’s deep gas reserves. Currently the government is evaluating bids by IOCs to carry out the work. To date drilling has reached 16,000 feet in Bahrain but the plan is to increase this to 20,000 feet. Ali Mirza hopes that if greater reserves are accessed in Bahrain it will, like neighbouring Qatar, be able to tap into growing world demand for LNG: “Our consultants say we have a good quantity (of deep gas), this is their estimate. We don’t want to project any figures because the bidders have bid, and we want to look at their projections and their evaluations first. Gas is the most valuable commodity now everywhere. It’s required for generating energy for the industry, for generating power and electricity, for use as a fuel in the petrochemical industry, so it is a commodity in demand, and we in Bahrain have launched 12 initiatives to secure gas because we don’t have as much gas as Qatar has currently.”

The effective use of new technology, including enhanced oil recovery techniques, is vital to the success of Bahrain’s many projects, and Ali Mirza says the country prides itself on its investment in the latest techniques: “Of course Bahrain has always been proactive in the use of new technology and we are currently using it both in the exploration for crude oil and in the refining sector. So for example, we have spent more than US$1 billion over the last 10 years to modernise a refi nery by using new technology. We have carried out major projects, for example, to produce unleaded gasoline and low sulphur diesel projects, and we are currently commissioning a new refinery gas exploration project. All these projects require new technology.”

“Bahrain has always been proactive in the use of new technology and we are currently using it both in the exploration for crude oil and in the refining sector”

As well as creating new facilities, Bahrain is investing heavily in maximising its existing resources, in particular the Bahrain field – the oldest in the Arabian Gulf at 79 years. Oil was first discovered there in 1952, signalling Bahrain’s entry into the global oil and gas market. The NOGA has signed an agreement with two international oil companies, Occidental and Mubadala, which, together with the newly formed Bahraini oil company Tatweer, will aim to triple current production at the Bahrain field from 33,000 barrels per day to 1200,000 in the next seven years.

“They will be using the latest enhanced oil recovery technologies such as steam injections, water flooding and gas injections. Tatweer will develop the onshore oil field with the latest technology such that the production of crude oil is doubled, from the current 30-35,000 barrels per day within five years and then trebled two years after that. In addi-

Investing in the future As well as investing heavily in exploration technology, Bahrain has also paid millions of dollars into projects to increase the sustainability of its operations. Last year the NOGA signed an agreement with Abu Dhabibased Masdar to develop ways to cut carbon emissions in the oil and gas sector. Describing some of the environmental projects the government has been involved in to date, he says: “We are very proud of what has been achieved, and the support that we have received for environmental projects from the very top of the government. For example, over 10 years ago Bapco developed an environmental investment programme to improve the quality of petroleum products and reduce environmental emissions.

Unfortunately these projects cannot be achieved over night. In the early

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The National Oil and Gas Holding Company

NOGA is owned by Bahrain’s National Oil and Gas Authority and represents the government’s interests in Bahrain’s oil and gas industry. Here Dr Abdul-Hussain Ali Mirza describes its role:

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e wanted the oil industry in Bahrain to be managed and operated with a commercial drive. The formation of NOGA in 2005, the political and regulatory body, was insufficient to make this happen alone, and therefore in 2007 we formed the Oil and Gas Holding Company. The Oil and Gas Holding Company (commonly known as nogaholding), is wholly owned by NOGA but is managed based on business and commercial principles. The company is the steward for the government shares in the Bahraini oil, gas and petrochemical companies and its original portfolio was comprised of Bapco, Banagas, Bafco and GPIC. Since the inception of nogaholding in 2007, the Bahrain Lube Base Oil Company (a joint venture with Neste Oil of Finland), Tatweer Petroleum and Banagas Expansion Company have been added to the portfolio. I also expect that several more companies will join the portfolio before the end of 2010. nogaholding is growing the portfolio and leading the existing companies to operational excellence and best practice. nogaholding has been set a financial performance target by the National Strategy 2009-2014 and is well on the way to achieving this target.

The creation of nogaholding was the right decision to encourage greater innovation and to ensure that government companies are managed with a commercial mindset. We are proud of the performance demonstrated by nogaholding to date.

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part of the decade Bapco eliminated the manufacture of leaded gasoline and the whole country went unleaded. More recently the refinery invested US$150 million to remove impurities from the Khuff gas and the project has reduced the SOx emissions to a level below the standard for refi neries in California. This is a clear example of how the refinery sets world-class standards. We also invested US$700 million in the refinery to manufacture ultra low sulphur diesel, and the refinery now makes the cleanest diesel in the world. Further refinery projects have addressed solid waste from the refinery and improvement of the excess water.”

But these cutting edge projects require major investment by the Bahraini government at a time when margins in the industry are tighter than ever. Ali Mirza admits the Bahraini oil and gas industry has been adversely affected by the economic downturn, but says, given the lengthy planning periods involved in constructing new refi nery facilities, he is hopeful that long-term projects will not be affected: “The global recession has impacted the worldwide demand for petroleum product and the corollary of this is a reduction in refi nery margins. Hence, the recession has defi nitely reduced our earnings. On the other hand, investments in this industry take a long time to develop from the initial idea to a plant in operation. Th is can often take between five and seven years. Our strategic investment plans are designed to position us for the long term and so we have not reduced this investment. Short-term investment has been modified but not to a great extent.”

As well as the fi nancial capital needed to realise its ambitious plans, Bahrain requires skilled human capital, which, like in every other country’s oil industry, could be in short supply as the current generation of oil and gas workers approaches retirement age. Ali Mirza describes the steps being taken to combat the problem: “If I may take you back to the 1960s, Bahrain faced the problem of developing a skilled workforce in the oil and gas industry and a cadre of young men and women were identified for further education. That programme was coordinated by Bapco in conjunction with the American company Caltex and the result was that

the major Bahraini companies are now predominately managed and operated by Bahrainis. It is not uncommon for our manufacturing companies to have a level of Bahrainisation of between 80 and 90 percent.

The additional benefit was that many national leaders, myself included, originated in that programme.

“However, what are we doing for the future? Today is a different world and the young people of today have different aspirations. However, we aim to recreate the successful development programmes of the past to ensure that the necessary academic and vocational education and training is made available to every young person in Bahrain.”

He goes on to reveal that the government is in the process of discussing plans for an oil and gas institution in the country to educate trainees and that it is focussing on the continued training of those already employed within the industry: “We want to create an institute for education in the oil and gas industry, and we have been discussing an arrangement with a prestigious, globally recognised university that specialises in courses suited to the oil and gas industry. Furthermore, we ensure that the training and development budgets of companies within the NOGA portfolio are generously supported such that employees of all ages are getting the necessary development as this is vital to the future. It is a great challenge for NOGA to demonstrate to the school leavers and the university graduates that a career in the oil industry will be rewarding fi nancially and in terms of job satisfaction.”

Ali Mirza’s own career success story should be motivation enough for aspiring young Bahraini oil workers to join the industry, despite the challenges it currently faces in today’s economic climate. He believes that Bahrain’s own part in the global oil story is only just beginning and that there is plenty of life left in the industry yet: “If anyone tells you that the oil industry is a dying industry, just take another look at the demand for hydrocarbons, the dependence of society today on the products from oil, and the reserves for the future. Oil will be a part of the energy solution for a very long time.”

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LEAD INTERVIEW

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As oil refineries face one of the toughest periods in their history, Bapco’s deputy CEO DR EION TURNBULL reveals what the

NING A

company is doing to stay one step ahead of the competition.

lthough Bapco may appear often in the news headlines for its workers’ strike action, the company is keener than most to publicise its employee welfare schemes. Press releases are regularly issued describing the latest health and safety programmes or staff training days. And according to Deputy CEO Dr Eion Turnbull, it is the empowerment of its people that differentiates Bapco from the rest of the region’s NOCs. “Fundamentally I believe these days, that if you look at different refi neries, the technology and the hardware that sits behind them is broadly the same. In fact the real difference between the pace setters and the laggers is the way people get engaged in the business and contribute to its success. I firmly believe the difference between the best and the rest is the people. At the heart of the organisation are the people, their loyalty and the people thinking that the managers care about them in a holistic sense and make them feel special.” He goes on to say that this is very often not the case at GCC-based oil companies. “Some companies

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willingness to provide workers with a voice by supporting the existence of a trade union. Indeed Dr Turnbull denies that Bapco’s record with regards to staff treatment is tainted and claims the only challenge it now faces in this regard is to ensure it keeps its standards up. “I think Bapco has an enviable history, in terms of safety, care and concern. The challenge for us now is how to maintain and sustain that because quite often when you are very good, there is a tendency to maybe take your foot off the accelerator and think you’ve done it.”

Safety first One of the ways in which Bapco aims to perpetuate its “enviable history” is through its strong focus on health and safety issues. Dr Turnbull points out: “If you have one big incident on the refi nery, you can go from looking very good to looking very poor very quickly.” As well as operating ongoing health and safety training schemes for its staff and funding some through higher education programmes, Dr Turnbull says the company is looking at ways in which to use technology to increase the safety of its workers. One such initiative he says is the installation

About Bapco

“I think Bapco has an enviable history, in terms of safety, care and concern” talk about issues like safety but you get a sense of them being driven by the wrong reasons. For example a manager might drive safety very hard because it’s going to affect his or her bonus, not because they really care about people or their well-being.”

Bapco is wholly owned by the Government of Bahrain and is engaged in exploration and prospecting for oil, drilling, production, refining, distribution of petroleum products and natural gas, sales and exports of crude oil and refined products. The company owns a 250,000 barrel-a-day refinery, storage facilities for more than 14 million barrels, a marketing terminal, and a marine terminal for its petroleum products.

Bapco’s prime customers for crude oil and refined products are based in the Middle East, India, the Far East, South East Asia and Africa, and 95 percent of its refined products are exported.

People power Elaborating on how Bapco’s approach is different Dr Turnbull says it provides support and training for employees’ career development, supports the families of injured workers and runs health and safety schemes such as a recent ergonomics awareness campaign. Despite this focus on employee welfare however, Bapco workers frequently strike over pay and working conditions, with the most recent industrial action taken in February when hundreds of staff protested against the company’s refi nery facilities, led by the Trade Union of Bapco Employees, which issued 52 different demands including automatic retirement for workers aged over 60. Similar strikes were held the previous February by around 700 workers demanding increased bonus payments. While these strikes indicate worker dissatisfaction, they are also perhaps indicative of the company’s

of remote sensing devices to detect the early signs of dangerous gas emissions. “There might be areas where there might, for example, be a release of volatile organics. The sensors can detect a combination of chronic and acute gases,” Dr Turnbull explains.

Technology is being used also to help the company reach its environmental targets, particularly reducing emissions of sulphur gases from its refi neries. In order to achieve this it is investing US$400 million in research and development to fi nd a solution. Describing the project Dr Turnbull says: “Previously our gases were not treated as thoroughly as we’d like to so not

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all of them ended up in our fuel gas. There were three major pieces of work. The fi rst major piece was to identify the different gas strains and to separate them, put them through different scrubbing units to extract the H2s and put them through sulphur recovery units. These are the modern recovery units where you actually have the three-stage conversion process with a unit at the end that really gets down to the very low levels of sulphur compounds released.”

Another environmental scheme the company is running is a state of the art new wastewater treatment plant that uses membrane technology combined with biological technology to clean up the fuels before they become released in wastewater. “This takes away wastewater and treats it through chemical processes and then through biological processes.

It was quite a challenging project because our wastewater streams have some characteristics that are unusual in terms of high temperatures and high levels of salinity. Also some of our specifications on clean water were much tougher than in other parts of the world. So getting the combination of tough conditions and tough criteria was difficult. What we ended up with was a membrane based biological system.” He goes on to say that

environmental schemes of this sort are all the more important given the increased future global demand for energy: “Sudden demand for energy to meet ever increasing needs really plays out on two sides. One side is how you actually restrict demand and how to be more energy efficient so you don’t consume energy in the production process itself. The other side is how you make more of the product itself.”

Competitive times But while Dr Turnbull is working to fi nd ways of sustainably meeting world demand, he also says one of the biggest challenges the company faces in the shorter term is the growing competition from new refi neries that are slated to open, particularly in emerging markets such as India – combined with the impact on short term demand from the economic downturn and growing eco-awareness. “There are a lot of facilities coming online and some big ones like the refi neries over in India.

And because of awareness of the environment I think that in the western world we’re going to see demand either shrink or stay very flat as they make moves to contain their energy consumption. What we’re seeing

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A diagram showing Bapco’s operations

around the world is that some refi nery projects have stopped altogether and others have been slowed down. We’re seeing shutdowns and shut-ins of refi neries on a scale that I don’t think we’ve seen in maybe 30 years. It’s having a profound impact on the industry at the moment.”

With this in mind, Dr Turnbull says he is working on ways to cut down on the company’s operational costs, “We are looking at how we can control our costs in a meaningful way during this period.”

The company is also forging ahead with plans to expand its refi nery capacity despite the gloomy economy prospects. Last year it announced plans for a US$2 billion expansion of its Sidra refi nery which would take capacity to between 350,000 and 400,000 bpd, from around 267,000 bpd. The success of the project depends on the building of a new pipeline from Saudi Arabia through which it will receive new crude oil supplies, which are expected to be pumped through from 2011. The company is also in partnership with the Finnish company, Neste Oil to establish a base oil plant. It will aim to take some of the lower grade oil streams from the hydrocracker and upgrade them to high quality base oils that can then be used for high performance engines. “It’s a major undertaking and that’s just the sheer logistics of getting all the equipment here on time and getting the right sequence of events around the construction and the commission of testing. You have got to be very careful with hydrocracker units.”

Like every oil company in the GCC, Bapco is working to achieve a delicate balance between planning ahead for increased global demand and adapting to current economic conditions, which have stifled it. Its ambitious expansion plans suggest however that its eye is set fi rmly on a brighter future.

“We are looking at how we can control our costs in a meaningful way during this period”

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NATURAL GAS

TURN UP THE GAS It may just be an 11,000 square-kilometre peninsula jutting into the Persian Gulf but Qatar boasts some 26 million cubic metres of natural gas. O&G looks at how this Arab nation is morphing into a gas superpower on the global energy stage as it sets its sights on new markets.

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hile the Arab world has been blessed with some of the world’s largest oil reserves, Qatar, partly due to its diminutive landmass, only has around 15 billion barrels.

Granted, resource-dry nations would give their proverbial right arm for this figure but for Qatar its black gold takes a back seat compared to its gargantuan gas reserves of 26 million cubic metres – around 14 percent of the world total. These reserves are the world’s third largest after Russia and Iran.

Since becoming the Emir of Qatar in 1995, Sheikh Hamad bin Khalifa Al Thani has invested mammoth sums in exploiting the enormous natural gas fields. Today, the oil and gas industry accounts for around half of the state’s GDP and almost three-quarters of government revenue. Qatar is also the world’s largest producer of liquefied natural gas (LNG) while its four new LNG plants will double production capacity. In 2008 alone, LNG capacity shot up by 40 percent. This rise, coupled with rising oil prices on the back of a weakening US dollar, will boost revenues and generate “phenomenal growth”, according to analysts. “Qatar’s biggest strength is continuous expansion in its liquefied natural gas capacity,” says Faisal Hasan, Head of Research at Global Investment House in Kuwait.

Qatar currently produces 54 million tonnes of LNG but this is set to mushroom to 77.1 million tonnes per annum by 2011. “These figures suggest notable progress, as output capacity amounted to 30.9 million tonnes a year only two years ago,” says Hasan. “The country has significant expansion plans to increase production over the next three years.” Qatar is shelling out US$100 billion on boosting capacity and upgrading infrastructure over the next few years. “Qatar has significant growth prospects left, with de-bottlenecking expected to add 12 million tonnes a year of LNG production capacity and a significant margin left to satisfy future domestic demand growth,” explains Samuel Ciszuk, IHS Global Insight Middle East Energy analyst.

Grand visions One of the main earners for Qatar will eventually be the Pearl gas to liquids (GTL) project based in Ras Laffan. Once constructed, it will be the largest GTL plant in the world and will operate under a production sharing agreement (PSA) between Qatar Petroleum and oil giant Shell. It is set to churn out 140,000 barrels a day of petroleum products. Phase 1 of the Pearl GTL is due to come online later this year. Shell senior executive Gerrit-Jan Smitskamp

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told Reuters that a 50,000-strong workforce is working on the project and that twice as much concrete has been poured compared to that used to construct the world’s tallest building – Dubai’s Burj Khalifa.

Qatar’s abundance of hydrocarbons are in hot demand, especially among emerging Asian economies. The US even received its first ever shipment of Qatar LNG in December. This is a process where the gas is cooled to 160°C, shrinking it by 600 times its original size. LNG, which is about twice as clean to burn as oil, is then shipped around the world in supertankers. In order to meet growing demand, investment has been made into its fleet of transportation vessels. “This has enabled Qatar to reach new markets that are otherwise not accessible, such as China, Japan and Europe,” Anani explains. “This is in addition to positively reducing the heavy cost of transporting LNG due to economies of scale, which in turn made Qatari LNG more competitive.” Dr

Eckart Woertz, Program Manager of Economics at the Gulf Research Centre, says Qatar is “heavily dependent” on energy exports. “Its challenge will be to enhance the value chain of its oil production into petrochemicals and heavy industries and prudent management of its foreign assets.”

In the pipeline One the major gas projects in the world right now is the Dolphin gas pipeline, which was conceived in 1999 to produce, process and transport natural gas from Qatar's North Field to the UAE and Oman, in order to support long-term industrial growth. The North Field is key to Qatar’s natural gas development and production plans. The project is one of the largest trans-border energy projects ever undertaken in the Middle East. The US$7 billion project has brought together three GCC nations – the UAE, Qatar and Oman

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– into an integrated regional energy network for the first time. This unique strategic energy initiative involves the production and processing of natural gas from Qatar's offshore North Field, and transportation of the processed gas by subsea pipeline to the UAE. The overall investment in wells, sealines, processing plant, pipelines and receiving facilities has made this one of the largest energy-related ventures ever undertaken in the Middle East.

Dolphin Energy’s overall objective is to create long-term economic wealth for GCC citizens, far into the future. The project includes the processing of gas at Ras Laffan to strip out condensate, ethane, LPG and sulphur, with the sweet lean gas delivered to the UAE through a sub-sea pipeline. Dolphin is now tasked with developing additional condensate storage in Qatar, Adel Al Buainain, General Manager of Qatar Dolphin Energy, told reporters, “There are a number of common facilities shared by a number of operators in Ras Laffan, and we are managing the condensate tank storage facility. We are supervising the construction of these new facilities.” The facilities are expected to be completed by mid-2010.

The downside of this surge in the energy sector – coupled with population growth – is the hefty environmental price. Qataris have the highest carbon footprint on the planet – a surprising statistic considering that the bulk of its energy comes from burning natural gas, which has half the emissions of coal. Qatar’s carbon emissions have quadrupled since 1990 as a result of its soaring energy use, fuelled not just by population growth but by the demands of its natural gas reserves and the amount of energy required to liquefy the gas. As a result, electricity demand in the country is rising by around seven percent a year. The government is, however, addressing these issues and last year unveiled aggressive strategies to reduce CO2 emissions through partnerships between industries and the government. It also launched a US$70 mil-

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lion 10-year project with Shell, Qatar Petroleum, Imperial College in London and the Qatar Science & Technology Park, aimed at reducing the country’s carbon footprint.

Rich pickings With a flood of cash coming in from gas revenues, the Qatari government isn’t just counting its money mountain in an ivory tower. No, hydrocarbon revenues are instead being pumped into diversifying revenue streams.

This ideology can be seen by Qatar Education City, Sidra Hospital, Hamad Medical Centre, Qatar Science & Technology Park and Qatar Financial Center. “The hydrocarbon related revenues are being put to prudent use, in my opinion,” suggests Ahmad Anani, a partner and head of law firm Al Tamimi & Company’s Qatari office. Anani says he believes the gulf state is doing an “excellent job” of diversifying its economy: “The country has a highly publicised vision focused at improving human capital, providing regional outstanding healthcare services, developing the education sector, promoting research and development and making the country a regional financial hub and an international financial centre in the longer term.” Infrastructure is a major benefactor of the hydrocarbon revenues, with the government budgeting US$20 billion alone for road projects over the next five years, as well as constructing a 22km bridge between Qatar and Bahrain that is projected to cost US$3 billion. The new US$1 billion airport, due for completion in 2011 with an annual capacity of 25 million passengers, will even include a US$1 billion sub-sea tunnel linking the airport with the financial centre. With other schemes in development, Qatar is joining the likes of Dubai and Abu Dhabi in terms of mega-projects. For Qatar, it seems gas really is its ticket to becoming a player on the global energy stage. n

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EXPLORATION FOCUS

FIELD OF

DREAMS Kuwait Oil Company (KOC) faces both technology and staffing challenges as it bids to ramp up output in the coming years. How the country’s NOC tackles these obstacles falls on the shoulders of Khalid Al-Sumaiti, Deputy Managing Director of Exploration and Production Development.

KOC has a 2020 strategy that includes your visions, values and objectives. What is its purpose and how are you progressing with the 2030 strategy?

Khalid Al-Sumaiti. Now we are almost finished with the 2030 Strategy, which has been endorsed by the board. We will aim to hit four million barrels per day by 2020 and continue at this level up to 2030. But we need to focus on people because the main challenge is to have the right resources in place at the right time. We are focusing on gas more because our target is to reach one billion cfd (cubic feet per day) by 2015 or 2016. So the theme of the strategy is to focus on exploration, and make that exploration into production as fast as we can. We also have targets for oil and I look at it as a challenge because I am in charge of exploration. We will achieve this by working in coordination with other assets in the north, south and west of the country. But we are on target to meet the 2020 strategy and there has been a lot of success that we want to build on for 2030.

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KOC is undertaking enhanced recovery (EOR) techniques, including water flooding. Could you give us an insight into these techniques and what they are achieving for your exploration efforts?

KS. Enhanced oil recovery really is a big part of our strategy and when we built our 2020 strategy we said that we have to focus on EOR. At this stage we have to select which reservoir and which technique we are going to use for EOR, whether it be CO2 or steam with heavy oil. So EOR is very much part of our strategy and we are working hard on it. We are also looking for a partner to work with us in this area. The water flooding started in north Kuwait and this is very efficient at enhancing the pressure and increasing production.

However, water flooding is not a complicated issue like EOR is, especially if we are talking about CO2 capturing. We have formed a steering committee to look at this in north, west and southwest Kuwait to see where we can implement EOR. We are at an advanced stage with this in north Kuwait but it is still in the selection stage right now.

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The entire north Kuwait region offers great potential for additional discoveries. What are you doing to exploit this area and what are your targets for it?

KS. In 2005 and 2006, when we announced the discovery of light crude oil and gas in north Kuwait, which obviously became an attractive region for us.

Recently, we announced another discovery of light crude and gas at the Mutreba field in the northwest of the country. So we are focusing on the north of Kuwait because we have a much better understanding of this area. We are trying to test other leads there too because the driver for more discoveries is the need for the government to generate electricity, especially in summer.

All our effort now, or the majority of our rigs in the north, are there to expedite and develop those discoveries, and put them in the pipeline as fast as we can in order to help our customer, the Ministry of Electricity. Because we have a discovery, the risk is low but the need is high to have gas, which is very important to us, from an environmental point of view. Gas is clean and friendly for the environment unlike gas oil or crude oil. So the effort is on exploration for gas and light crude.

How do state-of-the-art technologies help in KOC’s exploration work, such as geological and geophysical acquisition? Where else is technology critical in your operations?

“Although KOC is known as an oil producer, we are focusing more on gas and the driver behind this is the environment and the need to use clean fuel for generating electricity”

gies. This is why we are always doing research into new technologies with our partners, be it a university, an institute, IOC, or service provider.

How will your Oil Exports Facilities Project boost production and KOC’s export capacity?

KS. Whilst being focused on finding oil, you also need to think about your gathering centres and facilities. And if there are limitations at your export facility then there will be bottlenecks. So we have increased the number of storage tanks and transit lines so that we can now export three million barrels from our existing export facility. This is part of a big project we completed to upgrade the export facility, whilst we also upgrade all existing gathering centres.

Although oil is your primary concern, how important is gas to KOC’s operations and how much potential do you see in Kuwait?

KS. In the 2020 Strategy, there was a target to discover and to produce four TCF (trillion cubic feet) of gas. We exceeded that target when we discovered North Kuwait’s Jurassic fields. Now we are working to build another target in order to meet the country’s needs because gas is the top priority in our activity, whether it is in exploration or in development. With gas, as soon as you produce it you have to market it – you cannot just store it. It’s similar to oil in that respect. So although KOC is known as an oil producer, we are focusing more on gas and as I said before, the driver behind this is the environment and the need to use clean fuel for generating electricity. It also makes sense for us to produce gas from an economic point of view because in the summer we sometimes have to use diesel, which is very costly. So we need to explore for and find more gas as soon as we can and get it into production.

Khalid Al-Sumaiti

KS. Kuwait is a small country so we have to use the technology to overcome the challenges. It’s not a big area where you can go and carry out new exploration. The country is small and the majority of it has been scanned by seismic exploration many times. So the technology will be very important, especially when it comes to depolarising. We are working with partners to do more research into better imaging for depolarising so we can use the seismic as a tool to tell us the depolarsing structure – where there is a possibility of more gas and light crude oil. We have carried out several pilots and we are succeeding in better imaging.

The other challenge we have is how we can identify the fracture because the majority of the fractures depend on the porosity or the matrix. We need to identify and map those fractures so we can drill horizontally or at a high angle. It is also a challenge to drill deep in high pressure and high temperature locations, but again we have already conducted several successful pilots. So technology is needed to locate an area and once a prospect is identified you need technology to develop it because you need specific tools in these pressures and temperatures. Even with drilling, you are talking about more than 20,000 feet deep so there will always be a limitation with available technolo-

For years, the oil and gas industry worldwide has suffered from a skills shortage. How has KOC been affected by this and which areas of the company have been affected the most?

KS. This is an excellent question. When the oil prices got to more than US$140 it was difficult to find the right skills. Then the recession came in the fourth quarter of 2008 and there was an opportunity to get some skills. So it seems to be cyclical. But this cycle is affecting our business so we look at it as a longterm strategy and focus on the fresh graduates and the right number of people from the universities, train them well and put them into operation as fast as we can. We also have to keep them as resources for the country and for the future. We need to recruit from outside because we need experts so we look to recruit from all over the world. Are we meeting the target on everything?

No, we still have difficulty in this area. This is a market and good people are moving from place to place so we’re thinking of ways to retain our people, especially if they are experts.

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However, this is not just a challenge for Kuwait or the region – this is a problem the whole industry is facing. If you look at the average age of people in the upstream business it is 53 years. They account for 70 percent of all staff. Also, the number of people entering the industry as graduates has reduced because they choose to go into other industries like IT or law. So we have to work very closely with the universities to encourage people to go into the oil business. I think people like the SPE (Society of Petroleum Engineers) have to

Kuwaiti oil was first discovered in commercial quantities in 1938 78% of Kuwait’s oil is sold to non-Arab states The country’s reserves account for 8% of the world’s total play a big role in this, while the IOCs need to work very closely with the universities too to ensure the right people are attracted to go into the oil industry businesses, like petroleum or geology or geophysics. Every conference that we go to is an opportunity to share our experience and listen to other people on how they are trying to retain their staff. We think of it in the long term because you have to focus on the existing graduates and quickly get them into operation.

You say this situation is cyclical but how do you plan staffing levels and recruitment strategies alongside the volatile nature of oil prices?

KS. We have numerous recruitment campaigns where we go to the US, Canada, India or Egypt. When the industry is booming it is difficult to find people like geophysicists because there is a big need for them. When it goes the other way and oil declines to US$35 a small company cannot afford it so there are more geophysicists available. Our philosophy is that when we get good people we need to keep them in the country, make it attractive for them to stay in Kuwait, have good facilities and a good working environment.

However, we don’t have much flexibility on salary because we are a national oil company. Other companies can be flexible and dynamic and change salary scales in line with market conditions. We are fixed, so we try to solve this through special technical career ladders. n

INDUSTRY INSIGHT

A sign of the times Graeme Simpson on the challenges facing Middle Eastern national oil companies.

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here are a number of challenges facing NOCs in the Middle East today that differ significantly from those facing similar companies outside the region. In order to look more closely at these factors, it is useful to look at why they exist.

Specifically, it is the long-term viability of the province that raises these challenges. A useful benchmark to gauge the long-term viability of an oil province is the ratio of total reserves (R) to annual production (P), ie. the number of years of production remaining. Published R/P ratios show that for the Middle East as a whole this ratio is 79 years, (Kuwait 102), compared with the rest of the world at 25 years, (US 12, Europe nine, the UK six). Th is creates significant opportunities for the Middle East as well as enormous challenges in realising those opportunities.

The challenges of realising Middle East oil opportunites: Maintaining current production rates/fulfi lling quotas: Many of the producing fields are mature, needing careful reservoir management, including infi ll drilling, pressure maintenance, and installed capacity handling significant volumes of produced water.

Extending field life for the next generation: Many producing fields are huge, thus a small percentage increase in recovery efficiency can mean very large incremental volumes. Current state-of-the-art modelling techniques allow the screening, selection and detailed design of enhanced/improved recovery (EOR/IOR) programmes, allowing particular techniques to be more effectively targeted at areas providing maximum benefits.

Finding and producing new accumulations: These are often “difficult”, involving high temperature and pressure reservoir conditions, tight reservoirs, unconventional hydrocarbons (heavy oil and tight gas), and environmental issues, including CO2 disposal; Operating in hazardous former-confl ict areas: Areas that are potentially dangerous due to the risk from unexploded ordnance and landmines are a key issue in planning and implementing exploration/development activities. It is believed more than 1700 people have been killed or seriously injured. All operations should include

an assessment of risks posed by landmines or other munitions to alleviate risk to human health and understand potentially significant fi nancial implications.

Maximising net cash flow: All of this must make sound economic sense and therefore should involve detailed economic modelling of projected revenues and costs and, given the multitude of investment opportunities and strategic resource constraints, should include portfolio optimisation analysis.

The question, then, is how can NOCs most effectively face up to these challenges? History shows that this can only come from a collaborative effort. Many NOCs have very good, highly competent technical staff, but these are not sufficient, even with aggressive efforts to train in local and international universities. Organic growth of national capability is a long-term process which requires a commitment to recruiting and retaining quality staff. In this interim period, NOCs need to collaborate with IOCs, technology providers, and large consultancy companies in order to continue delivering in spite of these challenges.

The relationship between NOCs and IOCs can lead to a confl ict of interest. IOCs have capital, but so do NOCs, while IOCs have the expertise needed by NOCs. On the other hand, IOCs want access to and ownership of the petroleum produced, and this is sometimes understandably not acceptable to NOCs. NOCs have long-term relationships with major technology providers. However, here too there is a potential confl ict of interest. For when technology providers give strategic advice, this could be construed as directing the NOCs towards using that provider’s own tools. Consultants have no tools to sell (although they might have their own in-house tools which can be deployed effectively to complement industry-standard tools available from the major technology providers) and no interest in ownership of hydrocarbons. Additionally, they have a very experienced staff, usually with many years of experience. These consultants are able to provide expert, independent advice on demand, very cost effectively. Long term, the most successful NOCs will be the ones that are able to balance and manage multiple relationships most effectively.

Graeme S. Simpson is a Director with RPS Energy in London, responsible for business development in the Middle East. He has 33 years experience in the international oil and gas industry, and has published and lectured widely on reserves, resources, risk and uncertainty and their application to portfolio analysis and strategic decision-making.

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THE BIG INTERVIEW W

THE ENERGY

CHALLENGE

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In an exclusive interview, Matthias Bichsel, Royal Dutch Shell Executive Committee member and head of one of Shell’s four main businesses – its new Projects & Technology group – discusses how the global oil and gas giant is looking to meet the world’s energy needs in economically, socially and environmentally responsible ways.

By Rebecca Goozee

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he oil and gas industry faces new challenges everyday: the economic climate; heavier and more complex crudes; increased safety and environmental legislation; erosion of expertise with the exodus of experienced workforce members; and constant pressure for innovative new products to raise the game. But with these challenges comes opportunity, and by drawing on extensive global operating expertise, Shell’s Projects & Technology division is leveraging technology, expertise and experience to do just that. Responsible for delivery of all of Shell’s major projects, technical services and technology capabilities in both upstream and downstream, as well as overseeing safety and environmental performance, Matthias Bichsel is perfectly placed to answer for the industrygiant’s environmental performance and explain where the company is heading in respect of the energy challenge.

World energy demand is expected to increase by at least 50 percent by 2030. What role will oil and gas play in helping to meet that demand? And what are the challenges in order for oil and gas to remain a significant part of the energy mix?

Matthias Bichsel. In light of the world’s growing long-term demand for energy, the world will need to produce energy from all possible sources.

Of course, a much higher share of the world’s energy must come from non-hydrocarbon fuels in the future, but Shell’s own scenarios planning work makes it clear that oil and gas will continue to be the world’s primary source of energy for decades to come.

Even if a period of economic slowdown moderates demand growth, there is a major gap to meet. And we have to win that new production from increasingly difficult resources – smaller accumulations, in more complex geology or harsher conditions, that are more difficult to produce or get to market – all requiring new technologies, better capabilities and greater investment.

Getting increased production from mature conventional fields and difficult unconventional fields will both put upward pressure on the energy-intensity of operations. The future of the industry depends on our efforts to both increase efficiency and reduce our environmental footprint. We will need new technologies, skilled people, lean processes and huge fi nancial resources.

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As long as hydrocarbons are needed to meet the world’s energy needs, we will need to produce, process and distribute oil and gas effectively, efficiently and responsibly, using the skills and capabilities of all industry players. By combining the best of our technologies and skills through value-driven partnerships between national oil companies (NOCs) and international oil companies (IOCs), the oil and gas industry can achieve a higher production peak in the future, and push the peak back by years or decades.

How much pressure have the booming economies of China and India, as well as the West’s dependency on oil, placed on E&P companies to locate and extract new reserves? And, how are you going about locating and extracting new reserves at Shell?

MB. That is the energy challenge in a nutshell. Meeting accelerating energy demand will require producing increasingly difficult resources everywhere, applying greater understanding and new tools in complex projects. Many of the world’s future resources are located in the Arctic, or offshore in deepwater. And much is in the form of oil shale and oil sands – so-called ‘unconventional’ oil.

Shell is delivering major new resources where technology, integration and scale are key factors – from the North Sea to the Gulf of Mexico, from mining oil sands to tight gas drilling, and from standalone oil developments to integrated gas projects. To make sure we achieve this, Shell technology is extending the lives of wells and maximising our existing resources through enhanced oil recovery (EOR), sophisticated new digital programmes and clever drilling techniques.

In the 1960s, Shell used steam injection, which has proved to be one of the most successful ways of boosting oil recovery, in the large and complex Tulare reservoir of the South Belridge field near Bakersfield, California. We continue to pioneer EOR capabilities. A good example is Petroleum Development Oman, where we are working on a number of pilot projects. At Qarn Alam, steam injection assists the gravity drainage system already in place by heating the oil to reduce viscosity.

At Marmul, injected chemicals are expected to boost production by

around 10 percent. And gas injection is used at Harweel to free trapped oil. Injected oils produce a flooding effect, increasing the pressure in the well, helping to push the hydrocarbons to the surface.

Ormen Lange Our smart fields Ormen Lange was developed expertise provides both with sea-floor installations knowledge and control by inat depths of between 2800 tegrating digital information feet and 3600 feet. Following processing onshore, gas is technology with the latest transported 745 miles through drilling, seismic and reserthe world’s longest subsea voir monitoring techniques. pipeline to Easington on the east Combined with the expericoast of Britain. ence of geologists, engineers and others, smart fields can help increase the total amount of oil recovered from a field by 10 percent and gas recovery by five percent, while also boosting the rate of production.

New platform designs and new approaches to planning wells, such as our ‘Drilling the Limit’ methodology, have reduced the time it takes to drill wells, the energy used to drill them and the costs involved.

With each advance in well design and drilling, more of these valuable deposits can now be accessed. Shell’s ability to conquer the challenging deepwater environment provides access to oil and gas that lies deeper, is located in dispersed reservoirs or is difficult to produce. Thousands of technologies are developed and used to meet these challenges, from large, complex production systems to smart chemical treatments to help the oil and gas flow.

How have drilling and completion techniques evolved over the last few years? And how is technology helping drive advances in this area?

MB. In 2005, it would take 60 days to drill a 13,500-foot well in a tight gas field. Now it’s a little over three weeks, with technologies like rotary steerables and under-balanced drilling (UBD). Meanwhile, the wells are producing three to four times more than in 2005, due to technology improvements in areas like fracturing. So a drilling rig in 2009 can put 10 times as many hydrocarbon molecules in the pipeline as it did in 2005.

Shell has also found a way to adapt UBD, called pressurized mud-cap drilling. This technique facilitates accurate kick monitoring on wells with total loss of mud returns, reduces safety risks and dramatically reduces the fluid volumes required for safe annular feed. This can save US$1 million per well by reducing non-productive time.

In addition, we’ve developed a riserless mud recovery system that eliminates lost time on wells susceptible to seabed flow at depths up to 5000 feet. That has resulted in average mud and logistics savings of US$1 million per well. Shell has also pioneered a surface blow-out preventer system for moored rigs, first used last year offshore Brazil. Not putting the BOP on the seafloor eliminates the need for long and heavy risers. This, in turn, allows us to use older semi-submersible rigs or drill ships that cost much less.

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Energy projects are becoming increasingly technologically challenging. Take the Sakhalin II project, for example, that centres on some of the largest oil and gas reserves in the world. Can you explain the challenges specific to this project and how you have dealt with them?

MB. Sakhalin II is one of the world’s largest integrated, export-oriented oil and gas projects as well as Russia’s fi rst offshore gas project. When the Sakhalin II project is fully on stream, it will supply around five percent of the world’s liquefied natural gas (LNG) and make a significant contribution to strengthening global energy security. The Sakhalin II Project is developing two oil and gas fields (Piltun-Astokhskoye and Lunskoye) off shore northeast Sakhalin for production and export of crude oil and LNG. Sakhalin II has introduced the Russian Federation to a range of innovative technologies, from LNG production to offshore development of hydrocarbon fields. It has brought together Russian and international expertise to overcome formidable challenges and provides a potential model for similar collaboration in unlocking much-needed reserves in Arctic regions. Sakhalin II is the equivalent in size of five world-scale projects, located in a hostile sub-arctic environment, and covers a vast area in a region with almost no existing infrastructure. The float-over installation of the topsides for the PA-B platform set a world record at some 28,000 tonnes. The previous record was held by the Lunskoye-A platform at 22,000 tonnes.

There are also environmental, ecological and social sensitivities to be tackled. Two 800-kilometre pipelines, which bring oil and gas from the fields in the north of the island to the ice-free export terminal in the south, traverse mountainous terrain in an earthquake zone and cross more than 1000 watercourses, many of which are ecologically sensitive.

In all, the project adopted more than 800 additional environmental, safety and social commitments. As one of the early economic benefits, there are more than 25,000 jobs on the project, 70 percent of them fi lled

by Russian citizens.

Shell launched an initiative several years ago to improve the energy efficiency of its refineries and chemical plants. Can you explain more about this initiative and the impact it has had on improving efficiency at Shell?

MB. Improvements at our downstream facilities are already delivering CO2 emissions reductions of about one million tons per annum. We have deployed a wide range of techniques for cost-effective carbon and energy management across our operations for a number of years. We identify opportunities for energy-efficiency improvements, changes in feedstock or power generation, catalyst optimisation, carbon-capture technologies and CO2 sales.

At Shell, we have established an award-winning carbon and energy management consultancy that integrates technology and expertise from across the company. Our expertise is gained in reducing Shell’s own carbon footprint, and we offer it to the benefit of other companies facing the same challenges. Shell has been active in deploying technology across three key areas in order to reduce emissions: improving energy efficiency (such as energy optimisation and operational-excellence) generating energy cleanly (introducing renewable energy sources or switching to

Qarn Alam In November 2006, Shell launched Shell Technology Oman, an enhanced oil recovery (EOR) research and development hub that forms an integral part of the Shell Global Exploration and Production Technology organisation and works in close partnership with the Oil & Gas Research Center of Sultan Qaboos University and Petroleum Development Oman (PDO). Qarn Alam is one of the three EOR projects currently up and running.

less carbon-intensive fuels) and mitigation of emissions (preventing the release of CO2 into the environment by capturing it for sale to industrial users or for underground storage). We assess a client’s energy use and CO2 production and compare its current position with optimum operating practices. Strategies for mitigation are then proposed, which may include energy-efficiency or operational improvement programmes, carbon-abatement technologies, fuel-switching options, CO2 sales and carbon allowance trading and offsets. Energy cost savings are typically achieved through the intelligent application of technology and by modifying behaviors and processes. Programmes can be structured around minimal capital expenditure for rapid payback.

Can you explain how the energy efficiency programme was deployed at the Geismar facility and what impact it had?

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Champion West Located 56 miles off the coast of Brunei in the South China Sea is Shell’s flagship Smart Fields project, Champion West. After laying dormant for almost 30 years, Smart Fields technology and new drilling techniques have turned Champion West into one of the world’s most advanced oil and gas fields.

MB. The Shell Chemicals Geismar facility in Louisiana is a leading producer of ethylene-based industrial chemicals with a variety of end uses, including in the manufacture of detergents, antifreeze, plastics and textiles. The plant has a significant energy consumption; it uses, on average, 17 trillion Btu/yr of natural gas. In common with other Shell assets, Geismar places strong emphasis on environmental performance and continually assesses its energy consumption. In 2006, as part of a global initiative, we carried out an energy efficiency programme. The team reviewed energy balances, calculated potential benefits and worked with staff to identify energyefficiency improvement projects with technical and economic viability for implementation. Ten out of a possible 50 energy conservation projects relating to process equipment or systems were prioritized, including the optimisation of turbines, CO2 strippers and cogeneration facilities. After implementing the energy-efficiency projects, Shell Geismar estimated that it potentially avoided an extra US$14.7 million in energy costs over the two-year period 2006-2007, and reduced CO2 emissions.

What other steps does Shell take to minimise the environmental and social impact of its activities?

MB. For Shell, sustainable development means helping meet the world’s growing need for energy in economically, socially and environmentally responsible ways. Through our portfolio and products, we deliver benefits by providing the modern energy that people need to prosper, and help reduce energy’s impacts by offering cleaner products like natural gas, improved biofuels, and gasoline and diesel that help customers drive fuel more efficiently. Our operations look to create lasting social benefits, whether through employing local people or using local contractors and suppliers. We work to reduce environmental and social impacts at our operations in a number of ways: safeguarding the health and safety of our employees and neighbours; reducing disruptions to the community; reducing our impact on biodiversity; and using less energy, water and other resources when producing energy.

We have been working hard to reduce the emissions of local pollutants from our operations. Prime examples are nitrous oxide (NOx), sulphur dioxide (SO2) and volatile organic compounds (VOCs). Th is has involved a wide range of investments to upgrade facilities and install cleaner-burning equipment and SO2-capture technology. Since 1998, we have reduced SO2 emissions from our operations more than 20 percent and NOx emissions by more than 30 percent, even

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though we are now using much more energy to refi ne cleaner, lowersulphur fuel. And we have reduced VOC emissions from our operations by almost 65 percent since 1998. Contributing to sustainable development in this way requires a particular mindset or a different way of thinking about our day-to-day business. Th is means balancing our short- and longterm interests, and integrating social and environmental concerns into our decision-making.

cation, from contaminated natural gas and from refinery streams – and further differentiated our technology. Cansolv’s promising capabilities in SO2 capture will also allow us to further explore post-combustion carbon capture technology and solutions. We must ‘learn by doing’ in order to reduce costs, accelerate technology development and ultimately make carbon capture and storage (CCS) commercially viable on the back of emissions trading schemes.

Shell Global Solutions has acquired Cansolv, a firm specialising in the What technologies are key to transforming E&P operations at your development of emission capture systems. How do you expect this organisation? Are there any technical developments you are particuacquisition to impact the business? How do you hope to utilise the larly excited about? technology?

MB. Technology has delivered many positive surprises in the past and will MB. As global energy demand grows and the availability of easy oil and surely do so in the future. New technology will help us achieve a higher gas diminishes, strong gas treating capabilities will be required when production peak for hydrocarbons, push the timing of that peak back by unlocking new resources, such as sour natural gas or clean coal energy. years or decades, and to slow down the production decline that will take Cansolv Technologies Inc. develops ‘scrubbing’ technologies to capture place later. industrial gas emissions. It offers multi-emission technology for the conSimple technology breakthroughs have transformed the value of oil trol of sulphur dioxide (SO2) and other contaminants and a carbon diand gas resources in recent years. Our smart fields technology is a prime oxide (CO2) capture process for greenhouse gas reductions. The Cansolv example. The Champion West field in Brunei contains hundreds of small SO2 Scrubbing System is a regenerable amine technology for the removal accumulations, with thin reservoirs. Discovered in 1975, the field lay unof SO2 from combustion gases and it has been demonstrated in a variety tapped for almost 30 years, because we could not identify how to develop of applications, including oil refineries, chemical plants, utilities and nonit economically. The eventual solution in 2005 was to drill smart wells that ferrous smelters. snake vertically and horizontally through several accumulations We want to further develop technology that has the at once, with the ability to measure and control flow from potential to clean up contaminated gases and flue gases, up to seven separate sections. In 2006, Champion West predominantly SO2 solutions in the first instance. contributed up to 50,000 barrels a day to Brunei Shell With the addition of Cansolv’s technology to our and we are only at the dawn of the impact of Smart has the potential to portfolio, we have enhanced our capability to treat Fields technology. deliver an additional various compositions for syngas – from coal gasifiTime-lapse seismic, or 4D seismic technology, 50-60 billion barrels,

4D seismic

twice the known reserves of the United States

is another breakthrough. A study by CERA estimated that 4D seismic has the potential to deliver an additional 50-60 billion barrels, twice the known reserves of the United States. Use of 4D seismic in Shell has generated an extra half a billion dollars net income over the past 10 years in Europe alone.

The application of new technology can significantly shift the global energy equilibrium by opening up huge unconventional oil and gas resources. A few years ago, the US National Petroleum Council warned that it would be hard to maintain US gas production, and large-scale LNG imports would become necessary to meet domestic demand. But advances across the industry could open some 500 trillion cubic feet of untapped unconventional gas resources in North America, possibly considerably more.

That would supply current US consumption for at least two decades.

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EXECUTIVE INTERVIEW

Optimising workflows Arshad Matin of Seismic Micro-Technology (SMT) discusses eliminating bottlenecks in the exploration process, the challenges faced in the MENA region and trends he is witnessing in the industry.

Tell us a little about Seismic Micro-Technology.

Arshad Matin. Our market leading Windowsbased software, KINGDOM, helps companies reduce cycle times during prospect evaluation. We help over 2700 companies in 97 nations find and eliminate bottlenecks in the hydrocarbon exploration process. We have been in business since 1984 and will soon be located in seven offices.

Our headquarters are in Houston, Texas. Our additional offices are in London, Singapore, Calgary, Moscow, and most recently, Abu Dhabi.

We are also in the process of opening in Rio de Janeiro. Our newest offices in Abu Dhabi and Rio represent the areas where we are seeing the greatest interest for our software – the Middle East and South America.

In the last two-and-half-years that I have been CEO, we have focused on ensuring that KINGDOM provides next generation capabilities for even the most complex environments and can co-exist with the legacy multi-vendor workflows found within large E&P organisations. We think these are the key challenges for organisations today as they seek to cut their cycle times and reduce risk by optimising their workflows.

“Integration means higher productivity for organisations as they can reduce the time spent on moving data”

How do you help customers in this region?

AM. While our presence in the Middle East is newer than elsewhere, we believe we can offer the same value to this region as we have globally. The Middle East sees both unique opportunities and challenges in hydrocarbon extraction. It continues to have supplies that are the envy of the world, yet there is a growing need for sophisticated tools to extract these resources economically. At the same time, the needs of each customer and field are different. In Iraq, for example, there is a need for tools that aid in early field exploration. While in Saudi Arabia, understanding fractured carbonate reservoirs, for example, has become critical to success. And for the larger NOCs, the need to train a rapidly growing and young employee base on the newest technologies is often the biggest challenge ahead. So we work with each individual customer to understand their needs in the region, and tune our software, services and training to fulfill these specific needs.

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What are some of the new things you are doing at SMT this year?

AM. I have mentioned our increasing focus on Middle East and South American expansion but we have even more planned technologically. Throughout 2010, we are releasing what we see as the next generation platform for end-to-end field evaluation workflows. Next quarter we will release what we believe is the next generation in integrated geophysics and geology. KINGDOM will include the ability to execute an additional range of workflows including creating structural frameworks, 3D geomodeling, production forecasting and economic analysis. Most organisations today require four or more disparate tools to accomplish these tasks. This integration means higher productivity for organisations as they can reduce the time spent on moving data. Finally, we recognise that this problem of moving data needs to become easier for organisations. In fact, by one measure companies spend 20 percent of the prospect evaluation time just on this vital but extraneous part of the workflow. To eliminate this bottleneck, KINGDOM will release a brand new connectivity solution, using technology from our partner OpenSpirit, which will allow transparent, real time, bi-directional movement of data between KINGDOM and other major vendors.

Finally, how do you see the state of the mar-

ket in 2010?

AM. We see bright prospects ahead for the oil and gas market in 2010. Our two new offices this year attest to our faith. Even in 2009, our business yielded record earnings – and we actually grew our headcount in what was, otherwise, a tough year globally. While we think Peak Oil is still many years away, especially with new supplies poised to come online in the Middle East, we believe that increasing demand from emerging economies will continue to pressure prices upwards. And when our customers do well, SMT does well. n Arshad Matin is President and CEO at Seismic Micro-Technology. Under his leadership, the company has enjoyed unprecedented growth in revenues and profits. Since joining the company, Matin has focused on recruiting a new management team, setting new growth strategy, and expanding into new geographies and market segments.

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LEADERSHIP

FACING UP TO REALITY The financial crisis created a new world order in which oil and gas, like every industry, faces a whole new set of challenges. Saudi Aramco President and CEO Khalid Al-Falih reflects on these changes.

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he recent World Oil and Gas Assembly theme, ‘New Realities and New Challenges,’ assumes special significance in the midst of the fi nancial and economic turmoil that the world is going through. In fact, this backdrop is recasting the ups and downs that have always characterised the oil and gas sector. I would like to offer my perspective on how the fi nancial upheaval and other dynamics we will be exploring are changing the way our sector does business, and how their implications must factor into our forging a brighter, more secure energy future. It is difficult to approach any business discussion today without fi rst talking about the fi nancial and economic crisis. Like an earthquake, the crisis rocked much of the fi nancial sector, and its farreaching waves shook economies and markets around the world. While oil and gas were impacted by the crisis, our industry fared better than many other economic sectors. While not immune, the performance of oil and gas speaks to petroleum’s fundamental nature, and its importance as an essential commodity to virtually every aspect of modern life. Likewise, no geographic region or country has been unscathed by the deep recession, but fortunately, some emerging economies, such as India’s, were positioned to fare better.

The road to recovery Some say that the economic recovery has begun; others say we have a way to go yet. Th is latter viewpoint would certainly apply to harder-hit industries and countries. However, this much is certain: the world will emerge. After the downturn, and as economic expansion resumes, so will the need for energy – especially petroleum – to fuel economic activity. Two primary reasons for this demand are global population growth and rising living standards, closing the gap between the industrialised and developing worlds. My earlier remark about India’s favourable positioning during this fi nancial crisis leads me to the fi rst of four reality checks that I would like to highlight in seeking greater clarity on the role of oil and gas in the world energy future.

Our fi rst reality check is the growing shift of the economic centre of gravity towards the East – a phenomenon given even greater momentum by Asia’s dramatic population growth. Together, these economic and demographic trends are resulting in the emerging East accounting for a steadily rising share of global energy and petroleum demand. The developing economies of the world are at the heart of the International Energy Agency’s forecast that world primary energy demand will in-

crease by close to 40 percent by the year 2030, growing on average at 1.5 percent per year, with oil remaining the single-largest fuel in the energy mix. To put things in perspective, consider that in 1949, world population stood at about 2.5 billion. By 2050, global population is expected to exceed nine billion, with most growth occurring in developing nations.

The challenge will not be the number so much as the drastically escalating need for energy to help people realise their economic aspirations and lifestyle goals. Considering the vast future energy demand, the world will clearly need the contributions of all viable energy sources, including renewables, but the industry must help bring greater clarity to public perceptions about the factual future roles of various sources in the energy mix.

Th is brings us to our second reality check: for a long time to come, the world won’t be able to survive without fossil fuels. For the next few decades at the least, as the contribution of renewables increases from a small established base, fossil fuels will continue to dominate the world’s energy picture, accounting for a more than a three-quarters share among oil, gas and coal. As a proven and reliable resource whose accessibility and sustainability continually increase thanks to research, development and innovation, petroleum will remain indispensable to the world economy, and vital to nations reaching for a better way of life.

Meeting global demand In response to this long-term call for petroleum, Saudi Aramco is aggressively ramping up exploration, improving recovery and building our reserves year after year – indeed, increasing our capacity all along the value chain. While oil fields in many basins throughout the world are becoming increasingly mature, the share of the Middle East in global oil supplies will steadily rise. I am proud to say that Saudi Aramco has played, and will continue to play, an even bigger role as one of the key suppliers of oil to India, Asia and the whole world. At Saudi Aramco, our message of reliable and abundant petroleum supplies is substantiated in the expansion of our crude oil production capacity to 12 million barrels per day; the increase in our production of natural gas and gas products; our increasing refi ning capacity; and our expansion into the petrochemicals sector. In addition, our company’s spare production capacity plays a vital role in promoting oil market stability, as it has done in times of market turmoil or disruptions elsewhere to global supply. Maintaining this spare capacity is a huge commitment for Saudi Aramco, costing us tens of billions of dollars to build, and billions more to maintain – but this is an obligation we undertake responsibly, in the interest of global market stability.

While there is a good deal of euphoria around alternatives in many camps, over-promotion is a concern, given the likelihood that they may not be ready to shoulder a sufficiently large burden of world energy demand, because of inherent technical, commercial and economic viability challenges. It would be imprudent to assume that subsidies could be the acceptable basis for the long-term and large-scale application

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of alternatives. Of particular concern to our industry is the risk that over-confidence in alternatives could also distract from much-needed investment in oil and gas – and thus be severely counterproductive to energy security.

While alternative energy sources are being brought along, we mustcontinue our efforts in making the production and uses of hydrocarbons cleaner and more efficient. Another new reality is evident in the growth in oil supplies – and this constitutes our third reality check. With supplies of conventional oil maturing in many basins, the contributions of niche non-conventional oil sources are expected to continue rising, complementing the growing supplies of conventional oil from mostly major producers in developing nations. By unconventional oil resources, I mean natural gas liquids, condensates, heavy oils, and oil from extreme locations, like deep sea and the Arctic region, that carry very high development and operating costs due to their difficult environments.

New discoveries Technology has played a central role in making economically viable many of the non-conventional areas of oil and gas and has added enormous reserves to the industry’s portfolio. Some relatively recent examples of massive but expensive new discoveries include the Carioca and Tupi fields in offshore Brazil, which alone reportedly hold close to 20 billion barrels in reserves. Likewise, Saudi Aramco will also be venturing into the deep waters off the Red Sea coast over the next few years, including sub-salt plays.

Similarly, our Indian colleagues are looking at new opportunities both onshore and offshore, including deep-sea, following Reliance’s major gas discovery in the Krishna Godavari basin.

These examples demonstrate that there is no shortage of oil potential – as we know, the world’s oil reserves are abundant – but the complexity of bringing oil online increases significantly as we tap into more difficult conventional and non-conventional oil resources.

The unique circumstances and challenges that can be associated with more complex conventional and non-conventional oil set the stage for our fourth and fi nal reality check, which highlights the rising costs, wild swings in oil prices and lengthy lead times involved in developing energy projects in general. There are some compelling examples of this phenomenon from our own Khurais and Manifa mega-projects. At 1.2 million barrels per day capacity, the recently completed Khurais programme is the single-largest crude increment ever commissioned by the industry. When we made this investment decision, oil prices were in the range of US$55 per barrel with expectations of stronger prices; oil demand projections were healthy; and costs were in the usual range. Mid-program prices peaked at around US$140 per barrel. And yet toward the end of the programme,

prices had fallen to below US$35 and demand had tumbled due to the fi nancial crisis, while costs spiralled, doubling our investment. Our Manifa project, at 900,000 barrels per day capacity, is one of the largest heavy crude oil increments ever commissioned by the industry, but distinctive aspects of the field made for costs not typically associated with development. Manifa lies in shallow waters in the fragile ecology of the Arabian Gulf, requiring unique access solutions involving drilling islands. When we made this investment decision, oil prices were above US$70 per barrel, and as in the Khurais example, demand prospects were strong. Aft er contracts were awarded, however – again as with Khurais – prices declined to below US$35, demand projections fell, but costs did not proportionally decrease, clouding the robustness of the investment. We reviewed the programme, and with some execution plan modifications, including deferring completion by two years, decided to continue.

We pride ourselves in our ability to complete major projects such as these in record times. From conception to completion, Khurais took six years while Manifa will take nine years, partly due to its complexity. Our own experience with costs is consistent with the industry’s rapidly rising cost trajectory. For example, our brownfield Haradh III crude oil increment that came on stream in 2006 cost us about US$2500 per daily barrel. The cost of the grass-roots Khurais increment that has been recently completed was almost four times higher, while the cost of the more complex Manifa field, which will begin production in 2013 and be completed two years later, is expected to be more than seven times higher than the Haradh cost. Besides greater complexity, the rising capital cost trend has played a distinctive role in these higher costs.

Of course, non-conventional oil costs substantially more to develop.

Now considering the typical project cycle in our industry, there is an orderly progression of events from leasing of acreage to exploration to development, and that takes a long time. With environmentally sensitive, harsh locations and conditions, such progression can take up to 15 years or more. These long lead times can result from geographic and geologic challenges, and concerns for protection of the environment, as well as regulatory requirements.

And as the Khurais and Manifa examples I cited show, a host of key economic factors can change, impacting a project’s profitability or even its viability.

In the wake of the four transformative realities that I have discussed to this point, let’s turn our attention to how they relate to challenges facing us and explore how we can effectively respond, or better yet, proactively work with various stakeholders to achieve optimum results for both consumers and producers.

“Saudi Aramco invests heavily in professional development at all levels, and cultivates a corporate environment that stimulates and rewards excellence and innovation”

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Challenges ahead I would like to highlight two broad challenges: fi rst, the highly uncertain future energy environment and its implications for petroleum investments in particular; and second, ecological issues, including global warming. The uncertain and unattractive environment that is discouraging timely petroleum investments poses a critical challenge which the various concerned stakeholders, including the industry and governments, must jointly address. Because capital prefers certainty, a vague global energy future would discourage essential investments across the energy value chain. Th is scenario applies especially to fossil fuels in general, and to petroleum in particular, which is being singled out for harsher treatment in the global energy policy agenda. Unless addressed expeditiously, this environment will cause investment to fall behind demand growth, with negative implications for global energy stability. The confluence of three prominent factors is influencing the uncertain environment in which petroleum investment decisions must be made.

These factors are: the absolute level of oil prices and their volatility; an uneven regulatory playing field for competing energy sources, including carbon taxation plans; and political agendas and rhetoric impacting national and international energy policies, such as talk in some quarters of energy independence.

When it comes to price, excessive levels on either side are damaging. Prices on the low side discourage investments, especially in light of rising costs. On the other hand, excessively high prices impact economic growth, limiting the aspirations of people seeking better lives for themselves and their children. Financial speculation has played a detrimental role in amplifying price volatility, which is problematic to both producers and consumers. Efforts to minimise excessive speculation are a step in the right direction. The long-term nature of our industry and investments; the increasing complexity of our operations; and the various geo-

ity’s most pressing concerns, as environmental pressures, especially those related to greenhouse gas emissions and global warming, continue rising. Societal expectations on climate change are real, and the industry is expected to take a leadership role. At Saudi Aramco, one of our key corporate strategies is the pursuit of innovative research and technologies to minimise the environmental impact of our petroleum operations, with areas of focus including the desulfurisation of whole crude oils, cleaner-burning fuels, smokeless flares and lower carbon release. Th rough the establishment of our master-gas grid, we were able to eliminate gas flaring from most of our facilities. We also recognise the need to help develop cutting-edge carbon capture and sequestration technologies, and are actively involved in promoting technical solutions that reduce CO2 emissions from petroleum use. To help shoulder pragmatic climate-change research efforts, we are carrying out research and development in enhanced oil recovery using carbon dioxide flooding and long-term carbon dioxide storage as part of our own carbon management research programme.

Saudi Aramco’s environmental focus is not only reflected in our development and management of God-given hydrocarbon resources for economic and social benefit at home and abroad – we are also leveraging our natural environment in other ways to develop future energy sources. Saudi Arabia is richly endowed with oil and a highly favourable geology. But the Kingdom is also beginning to leverage another of our prime competitive advantages: plenty of bright sunshine, vast, open spaces of desert, and miles upon miles of clear sand. I invite you to re-imagine this desert environment’s roughly 3000 annual sunshine hours, in contrast to geographic areas with cloud cover during long periods of the year, which gives us solar potential among the highest in the world; stretches of desert, where vast arrays of mirrors can concentrate solar energy; and deposits of clear sand, which can be used in the manufacture of silicon photovoltaic cells.

Saudi Aramco is partnering with one of our affi liates – Showa Shell, a leading advanced photovoltaic cell manufacturer – to build two pilot solar plants. Concentrating solar power, commonly referred to as CSP, or the thermal approach, is another solar technology area that Saudi Aramco is helping promote. The King Abdullah University of Science and Technology, or KAUST, the new international research university on Saudi Arabia’s Red Sea coast that our company was privileged to help build, was established for the very purpose to explore solutions to global challenges.

KAUST has created the Solar and Alternative Energy Science and Engineering Research Centre to support solar as one of its core research areas. These activities demonstrate a commitment to ameliorate the environmental footprint of our operations and products through both conventional and unconventional routes. What is more, they underscore a long-term strategy to offer a wider energy portfolio to serve burgeoning global demand. It is my earnest hope that such considerable investments of capital and human ingenuity in both the petroleum and solar arenas will help recast some public misperception regarding our industry’s approach to energy and the environment.

“Another of the industry’s biggest challenges is also one of humanity’s most pressing concerns, as environmental pressures, especially those related to greenhouse gas emissions and global warming, continue rising.” political, environmental, regulatory, cost and other concerns that factor into shaping the industry landscape; underscore the need for jointly creating a climate that makes worthwhile significant commitments of capital and time that span decades.

Thus I would urge decision-makers across the globe to help create such a favourable investment climate to grow petroleum supplies in a timely fashion, which I consider to be a critical factor in enhancing energy security in general, and the security of petroleum supplies in particular.

Another of the industry’s biggest challenges is also one of human-

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EXECUTIVE INTERVIEW

Crude awakening O&G catches up with First Crude Oil’s Jan Strom to dig a little deeper into the latest industry trends.

Capital expenditure of oil and gas companies, after surging from 2007 to 2008, witnessed a significant decrease in 2009. How will your company adapt to these changes?

Jan Strom. Together with our partners, Subsea Norway AS, Jotne E&P AS and First Crude Engineering Inc., we have met these new demands by designing low cost and low weight subsea manifolds to reduce the overall project cost.

And it is not only material cost but also developing installation friendly subsea structures that are easy to install and retrieve by ordinary installation vessels. This has been completed without reducing material quality or designing equipment that can easily break.

We have focused on solid and reliable equipment that meets all international standards and with the functionality required by the oil and gas industry. Basically, we made a whole new concept, starting with P&ID’s to see what was needed with regards to functionality and cutting down on all ‘nice to haves’. The oil and gas companies are asking for equipment to recover hydrocarbons, without spending a fortune on CAPEX, and that is what we have designed.

spend less time offshore, thus reducing gas emissions, and as an extra bonus it saves a lot of installation cost. It is a win/win situation for the oil and gas companies and the environment. In addition to this, we are currently working on a drill cutting re-injection system that reduces the need for costly handling and transportation of this type of waste.

Jan Strom, who has an engineering degree in Marine Engineering and Electronics, is the Engineering Manager of First Crude Oil Ltd. Strom has been working with subsea engineering offshore and onshore for more than 20 years and was the co-founder of the Norwegian AMEK group.

quires less machining, welding and painting.

We have also focused on environmental impact at the design stage, and since our equip-

“We have focused on solid and reliable equipment that meets all international standards and with the functionality required by the oil and gas industry”

In recent years there has been an increased focus on environmental impacts from the oil and gas industry. How will your technology meet these new demands?

JS. We have designed a new type of subsea equipment that is built with less steel and re-

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ment is significantly smaller and lighter than conventional subsea structures the environmental cost for moving and installing is reduced by 50 percent compared to conventional structures. If the subsea equipment is as installation friendly as ours, intervention vessels

What are the financial benefits of this new technology developed by First Crude Oil? JS. First of all it will reduce CAPEX spent on a subsea field development by 25 percent and, in the long run, also reduce maintenance costs dramatically. But since many operators are now also looking at developing fields with less production lifetime, we have designed our new subsea production systems to be installed and retrieved numerous times. Our SPS equipment can be placed at one location for three to five years, then be removed and refurbished and put into new service at a new location. And you can even lease it for a certain period and then hand it back to us, saving a lot of operational cost for the operators and owners. We can then re-use the equipment with a new client at a new location. Of course, some of the major safety components have to be replaced, but still, it is a very cost effective field development solution.

Has First Crude Oil received any feedback on these new solutions?

JS. Yes, we have started marketing this new field development concept in the Asian and Middle East markets and all our clients are very interested to learn more about these low CAPEX subsea solutions. And we are just finishing our first field development study with this new technology and will shortly issue it to some of our main clients. We expect to launch the first subsea system by the end of 2010. n

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COMPANY PROFILE

SUCCESS STORY Celebrating its 90th anniversary this year, Occidental Petroleum Corporation (Oxy) managed to boost its profits, increase proved reserves by eight percent and replace 206 percent of 2009 production through improved recovery and new discoveries. And Oxy’s activities in the Middle East contributed significantly to its success. O&G reports.

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fter being an active investor in the Middle East and North Africa for over 40 years, Occidental has recently identified this region as one of its core strategic areas for the years to come. In 1965 the company decided to start international exploration and discovered a number of giant fields in Libya. Since then, Occidental has expanded its presence in MENA with operations in the UAE, Qatar, Oman, Yemen and Bahrain, and, collectively, its current assets in the region account for over 27 percent of the company’s worldwide production. During his 20-year leadership as Oxy’s Chairman and CEO, Ray Irani has spent a lot of time developing strong relationships with government leaders in almost all of Middle Eastern countries. Th is has given Oxy a competitive advantage in establishing credibility similar to that enjoyed by significantly larger oil companies when being considered for business opportunities. Additionally, under Irani’s leadership, Occidental has built an effective team that has contributed to Occidental’s Middle East success in business development and in operational projects.

New projects For sometime, Occidental’s MENA operations have been largely dominated by its involvement in Qatar’s Dolphin Project, one of the world’s premier transborder energy ventures. With a 24.5-percent undivided interest, it will be a steady contributor to Oxy’s fi nancial performance over the next 25 years and a significant influence on the region’s development. The Dolphin Project delivers natural gas from Qatar’s offshore North Field – one of the world’s largest gas reservoirs – to an

onshore processing and compression plant in Ras Laffan. Each day, this massive plant produces approximately two billion cubic feet of natural gas and 200,000 barrels of liquids, which flow through a 48-inch, 230-milelong subsea export pipeline to customers in the UAE and Oman.

However, despite already being a proven leader in cost-effective increased production from mature oil and gas fields, Oxy has recently strengthened its status in the Middle East with two brownfield development contracts. First, in November 2009, Oxy signed a contract with Mubadala Development Company and the National Oil and Gas Authority of Bahrain and announced the creation of a new joint operating company for the redevelopment of the Bahrain Field. The consortium plans to spend US$1.5 billion on a project aimed at almost tripling the field’s current output to 100,000 barrels per day. Two months later came another historic win – a contract to redevelop the massive 4.5-billionbarrel Zubair field in Iraq, one of the largest discovered oilfields in the world. Together with partners – Italian energy giant Eni and Korea Gas Corporation (KOGAS) – Oxy plans to spend about US$20 billion over the life of the 20-year contract to increase production from Zubair to 1.125 million bpd within the next six years from the current 195,000 bpd and maintain the target production for seven years thereafter. Moreover, the project includes the drilling of more than 200 wells, the construction of treatment facilities and the required collection network, as well as the refurbishment of the existing plants.

All of this suggests that Occidental is poised to have another successful year in MENA, once again establishing itself as one of the most successful international oil companies operating in the region.

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Oxy’s other MENA operations 3. Oman 1. Qatar In addition to the Dolphin Project, Oxy participates in three other developments: Idd El Shargi North Dome (ISND), Idd El Shargi South Dome (ISSD) and Al Rayyan (Block 12). Oxy’s success in Qatar helped to establish it as one of the world’s premier companies in EOR from mature fields. Since taking over operation of the ISND field, Oxy has reversed nearly 25 years of steadily declining production to 120,000 bpd through waterflooding and application of innovative drilling techniques and state-of-the-art reservoir characterisation.

Oxy’s Oman operations are concentrated at the giant Mukhaizna oil field in south-central Oman, the Safah field in northern Oman, and adjacent areas. During its 30-year tenure in the country, Oxy has increased its production, reserves and scope of operations through successful EOR methods, extensive 3-D seismic surveying and an 85-percent exploration drilling success rate. One of the largest fields in Oman, Mukhaizna has been under Oxy’s management for five years, during which an aggressive drilling and development programme was implemented, including a large-scale steam flood project to fully develop the field’s enormous heavy oil resources.

Today’s goal is to increase production 17-fold to 150,000 bpd within the next few years.

4. Yemen Oxy is one of the most active E&P companies in Yemen, with significant interests in both of the major oil and gas producing regions. The company holds a 38 percent working interest in the giant Masila Block where some of the world’s largest oil discoveries were made in the 1990s. Oxy also holds a 40 percent interest in the adjacent East Shabwa Block (Block 10) and is the operator of Block S-1, Block 20 and Block 75, located in the Ma’rib-Shabwa basin.

5. Bahrain 2. Libya Libya, one of the world’s most attractive exploration regions, plays a key part in Oxy’s business. Being the largest net oil and gas acreage holder in the country, Occidental was the first American company to resume oil production in Libya when US sanctions were lifted in 2005. That year, the company dominated the country’s first post-sanction exploration licensing round, winning nine of 15 exploration blocks and re-entering its original producing areas after a 19-year absence. In 2008, Oxy reached new 30-year agreements with Libya to redevelop and explore in its most prolific producing area – the Sirte Basin.

Apart from the onshore Bahrain Field, Oxy is also working with Bahrain Petroleum Company and the National Oil and Gas Authority of Bahrain to further explore offshore Blocks 1, 3 and 4.

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ASK THE EXPERT

A different perspective Nicholas Newman on why many refineries are now looking to gasket-free, compact plate heat exchangers as a reliable, cost-efficient alternative to traditional shell-and-tube heat exchangers.

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he most common type of heat exchanger in process plants today is the shell-and-tube. However, shell-and-tube heat exchangers are associated with high maintenance costs and excessive downtime. In addition, low thermal efficiency results in high installation costs and large footprints as well as excessive energy consumption and emissions. Fully welded, gasket-free compact plate heat exchangers like Alfa Laval’s Compabloc, on the other hand, are a well-proven and cost-efficient alternative that offers advantages like: • Reduced maintenance costs and improved reliability • Better thermal efficiency • Reduced heat-transfer area for lower CAPEX • Energy savings and reduced emissions (CO2, SOx, NOx)

Today Alfa Laval’s compact heat exchangers have been in successful, long-term operation in many critical processes in over 180 refi neries around the world. Alfa Laval’s compact plate heat exchangers use corrugated plates between the heating and cooling media.

Th is creates high turbulence and a cleaning effect that reduces chemical fouling. Compact plate heat exchangers also have a multi-pass arrangement with an overall counter-current flow, which means more heat can be transferred from one stream to another, or a heating media can be used that is just a few degrees warmer than the cold media. Together with the high turbulence, this allows high heat recovery and provides high heat-transfer coefficients, allowing significant size and weight reductions, low acquisition costs (CAPEX) and reduced energy use and emissions.

Reliability and availability

Compact plate heat exchanger installation for heat recovery in a desalting process. The three compact plate heat exchangers to the right replaced the six shell-and-tube heat exchangers to the left.

Alfa Laval’s compact plate heat exchangers have proven to provide many times longer uptime in critical refinery processes than shelland-tube heat exchangers. For example, one of US$68 million. In addition, the small size of the longest operating installations is in a bitucompact plate heat exchangers means that they men refinery in Europe. Here, 14 compact plate require only a fraction of the space needed by heat exchangers are in operation, the oldest shell-and-tube heat exchangers. So there are also since 1996. They have replaced shell-and-tube savings to be had on foundations, constructionheat exchangers in duties such as ADU fracal steel work, and the like. tion cooling, VDU overhead Finally, lower energy use vapour condensing and bitudue to better heat-transfer men heating and cooling. efficiency and increased heat The old shell-and-tube recovery gives reductions heat exchangers required in operating costs and CO2, cleaning and inspection SOx, and NOx emissions. yearly, which took a full week. The compact plate Global company, heat exchangers, on the other local insight hand, require only a single With a staff of over 100 day of chemical cleaning specialists at offices in the every third year. In total, for UAE, Saudi Arabia, Iran, the 14 units, the refinery has Egypt and Pakistan, Alfa reduced maintenance costs Laval can provide complete by 96 percent.

Nicholas Newman is currently the Regional Process Division Manager solutions for its customers for Alfa Laval Middle East Ltd. He has Lower acquisition wherever they are, at every over 15 years of experience working to bring efficient solutions to oil and gas costs stage of their projects. Alfa companies, refineries and engineering companies around the globe.

Because compact plate Laval acts as a partner to its heat exchangers are so efficlients, evaluating their needs cient, they require relatively little heat-transfer and processes and helping them design and implesurface compared to shell-and-tube heat exment the most efficient, reliable and cost-effective changers. This means that one compact plate solutions possible. heat exchanger can often replace a number of In addition, Alfa Laval has service centres shell-and-tube heat exchangers. So there are in the UAE and Saudi Arabia. This allows them significant savings to be had in capital outlay. to carry out field service, provide performance For example, in one planned installation, 12 agreements, condition-based monitoring and compact plate heat exchangers will replace 28 maintenance of heat exchangers across the shell-and-tube heat exchangers for a saving of Middle East.

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REFINING FOCUS

A chemical

reaction The petrochemicals refining industry underpins the Saudi economy and the growing numbers of international oil companies that are investing in its future. Here Ali AlNaimi Saudi Arabia’s Minister of Petroleum and Mineral Resources explains his vision for the industry.

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ithout question, the soundness and growing diversification of our regional economy will help restore calm following the turbulence of the moment. And of course, one of the fundamentals of our region’s economic strength is the petrochemicals and chemicals industries. I wish to explore the main factors affecting the development of the industry. First, it is always useful to think about where the industry has been as we think about where the industry might go in the future. We are in a world where changes happen more rapidly than ever before. Industry evolution should not be the exception, but in fact the expectation. Second, I will talk about the general picture today and going forward from the view of an oil and gas producer. Chemicals are a significant and growing portion of the global petroleum industry, but as we all know the petroleum industry is very broad and strategic not only to companies, but also to countries.

Lastly, I want to talk about the future in terms of how we can cooperate and collaborate with one another towards a greater good for both the region and the world and for the betterment of this great industry.

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A brief history In terms of historical growth, it is well documented that our region has attracted investment in the chemicals industry because of our sustainable competitive advantages. These advantages include not only reliable, affordable supply of feedstock but also location and port facilities convenient to serve Asian and European markets. Additionally we have the advantages of the regulatory and political stability in the Gulf and good relationships with partners who helped us build our own competencies over the years. As a result, our region today boasts some of the largest and most efficient, modern facilities in the world after starting from very modest means in the late 1970’s. From the earliest days of petroleum production in Saudi Arabia until as recently as the 1970s, much of the gas that was brought to the surface with oil was flared. This same situation existed throughout the Gulf. In our case, the decision to end gas flaring and transform the gas from a wasted commodity to a useful resource involved taking a long strategic view. The first piece of the strategy was actually to collect the gas and connect

“In terms of historical growth, it is well documented that our region has attracted investment in the chemicals industry because of our sustainable competitive advantages” the Kingdom from the oil fields in our Eastern Province to potential users as far away as the west coast through creation of the Saudi Master Gas System, which took place in the 1970s.

Saudi Arabia confounded the shortsighted by undertaking a strategic, long-term investment in a massive project to utilise hydrocarbon production capacity. This system has given us access to resources used for electric power generation, energy for water desalinisation plants, and abundant, competitively priced feedstock for petrochemicals.

The industrialisation saga continued with investment in what observers at the time called the biggest construction project in all of history – the creation of the modern industrial cities of Jubail on the East Coast and Yanbu’ on the Red Sea shore. A special Royal Commission was established to build the infrastructure for the two cities. Finally, in 1976, Saudi Arabia created the Saudi Basic Industries Corporation, or SABIC. SABIC, which Engineer Al-Mady so ably leads today, was assigned to initially develop the primary industries in the Royal Commission cities. With SABIC and its partners, the Kingdom moved defi nitively into using gas associated with oil production to manufacture value-added materials such as fertilizers and petrochemicals. At the beginning of the 1980s, direct investment in the Saudi chemical industry was about US$2 billion dollars. The goal at the time was simple – just to enter into the chemicals business. By the end of the 1990s, such investment had increased to approximately US$20 billion and the goals of the industry began to change, from merely learning the business to operating in a self-sufficient manner. Today SABIC continues to grow and prosper as an industry leader.

Th irty percent of the shares of SABIC are owned by private and institutional shareholders in GCC countries. SABIC continues to leverage its strengths in numerous domestic and international joint ventures. Saudi Arabia now also has many private players in the chemicals industry, making a dynamic contribution to the market and to this association. In addition to SABIC, 13 other chemical companies are listed on the Saudi Tadawul Stock Exchange.

From a single petrochemical mega-complex in 1983, the nation now has 24 mega-complexes, 14 of which are international joint ventures and several others are either under construction or planned.

largest methanol producer and the second largest ethylene producer. By 2015 the Kingdom’s petrochemical production is projected to increase from today’s levels of about 60 million tons per year to more than 80 million tons per year. The evolution of downstream industries is accelerating – moving beyond even the most sophisticated physical products toward sustainable leadership in human capital and advanced research. And industry analysts project that direct investment in the Saudi chemical industry by 2015 will far surpass the 100 billion dollar mark. Th is is quite remarkable when put into context, but we have seen growth stories in the chemicals sector occur throughout the Gulf, with each country charting its own way forward. Taken as an entirety, GCC chemicals production appears set to move to greater and greater heights.

The goals of the business are changing as well. The chemical industry in the Gulf is no longer simply operating facilities to manufacture products; it is becoming a key enabler of other industrialisation activities.

But before we talk about shaping the future, we should focus on an area of the business which, like chemicals, touches our lives every day: the upstream oil and gas sector.

The upstream industry is based on a declining resource model. In other words, the early days of an oil and gas field are often its best days from a fi nancial point of view. Th is may be counter-intuitive for those in the chemical industries who, after a start up period, expect to operate facilities for several decades and require relatively modest capital investment to maintain or de-bottleneck facilities. A major change that has taken place during the past few years is that the Saudi Arabian Ministry of Petroleum and Mineral Resources has begun to take a more vital, strategic role in allocating feedstock to diversify and strengthen the Kingdom’s economy. In Saudi Arabia, we are blessed with abundant natural resources, and we were able to overcome challenges and provide competitively priced gas and NGL products fostering strong growth in our chemical industry. During the past 15 years, we have

62% of chemical production in the GCC comes from Saudi Arabia

Future potential Saudi Arabia today accounts for about 62 percent of chemical production in the GCC region and approximately eight percent of global production. It is already the world’s

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been able to add massive new investments in Hawiyah and Haradh as well as our new gas development at Karan and our new ethane straddle plant. Besides a record number of wells being drilled by Saudi Aramco directed at new hydrocarbon sources today, we also have opened up exploration for new gas in the southern part of the Kingdom through our foreign partnerships with Shell, Sinopec, Lukoil and ENI. Stewardship of our natural gas resources is a strategic strength for my nation and for our region and beyond. A programme that began not too many years ago, based only on making productive use of associated gas that would have been flared, today has been transformed dramatically, for the economic benefit of the entire world. Even as we have produced vast amounts of natural gas, our production and reserves continue to increase. In 1990, Saudi Arabia’s natural gas reserves were 181 trillion cubic feet (TCF). At year-end 2008 they were higher, at 263 TCF, and we project that in 2010 proven reserves will be still even higher, as Saudi Aramco targets discovering a minimum of five TCF of additional non-associated gas reserves annually. Investment and application of new technologies are leading to greater abundance of natural gas. Another important factor is the change in the ratio of non-associated to associated gas. For instance in 1990, 75 percent of our natural gas reserves were in production. In 1981, Saudi raw gas production was 1654 million standard cubic feet per day (MMSCFD). Today it is approximately 8800 MMSCFD, and we project production levels to exceed 13,000 MMSCFD by 2020. Th is means our investment and management strategies are succeeding in meeting our target gas, whose production can be constrained by the factors of oil production. Today non-associated gas accounts for 48 percent of total gas reserves, and we expect it to constitute a significantly higher proportion in the future. There is comparable good news in gas of always staying ahead of demand for natural gas – toward all of its end uses in power generation, desalinisation, and chemical feedstock.

International partnerships We see the future of the chemical industry evolving so that local producers foster further investment and creation of knowledge in many

different sectors. I can offer a few observations about the future situation from a Saudi Arabian viewpoint. Our own national approach involves linkages between refi ning and chemical industries both inside and outside the King-

such as speciality chemicals and engineering thermoplastics. Saudi Arabia now actively encourages private investment in the chemical sector in order to strengthen our position as a global chemical leader and to diversify towards

“During the past 15 years, we have been able to add massive new investments in Hawiyah and Haradh as well as our new gas development at Karan and our new ethane straddle plant” dom. On November 8, 2009, Saudi Arabia celebrated the inauguration of Petro Rabigh, the largest integrated refi ning and petrochemical complex ever built at a single time. Th is US$10 billion facility will be producing more than 18 million tons of petroleum-based products per year, with some two-and-a-half million tons per annum of ethylene- and propylene-based derivatives. Petro Rabigh is jointly owned by Saudi Aramco, Sumitomo Chemical Company of Japan, and private and institutional shareholders who acquired equity in the company in 2007 in the first Initial Public Offering involving Saudi Aramco.

Saudi Aramco this year has also inaugurated another significant international joint venture in chemicals – the Fujian Refi ning and Petrochemical Company, in partnership with Sinopec of China and ExxonMobil. Th is enterprise, in Fujian Province, expands a refi nery’s capacity and adds new petrochemical facilities.

The new petrochemical complex includes an 800,000 tons-per-year ethylene steam cracker, an 800,000 tons-per-year polyethylene unit, a 400,000 tons-per-year polypropylene unit and a 700,000 tons-per-year paraxylene unit. Back at home and in the near future, Saudi Aramco is developing major integrated refi nery-based chemical complexes through joint ventures with Dow Chemical in Ras Tanura, with Total in Jubail, and with ConocoPhillips in Yanbu.

In addition, the Jazan refi nery which is up for competitive bidding provides opportunities for petrochemical synergies.

In the coming years, Saudi Arabia is poised for increases in the quantity and quality of our exports. We will diversify our chemical portfolio into more complex, distinctive products

value-added speciality chemicals, formulated products, and performance polymers. Other opportunities will be found with various SABIC projects and Petro Rabigh Phase II, and other private sector projects are all working to develop projects with higher know-how content which will add to the technology profi le of the industry and the utilisation of novel, proprietary processes. Our aim is to be able to produce a substantial number of upstream products as well as a range of sophisticated downstream products for the development of the local market and the world market.

In connection with this, the Government of Saudi Arabia has initiated the Saudi Industrial Clusters programme to develop and to provide support to a range of new industries.

The programme aims to grow and diversify the national economy by developing targeted industrial sectors that leverage the Kingdom’s natural resources, including the petrochemical industry products, and our young and growing Saudi workforce. The sectors have been selected in areas where the Saudi Arabian fundamentals of abundant, competitive energy and basic materials can be leveraged to create competitive ventures that meet the aspirations of both the nation and the investor.

The selections have been made only in sectors where we believe that over time Saudi Arabia can become competitive on a global basis. Key sectors now are being developed, each representing a different category of manufactured products: automotive value chain, metals processing, plastics, consumer goods, and solar.

As you can see, the clusters programme will create not only manufacturing industries but also will spur additional development in the

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utilisation of our mineral resources. Our goal is for global and regional markets to contain not just basic products but also a significant number of consumer and industrial products labelled ‘Made in Saudi Arabia’.

Knowledge creation The Saudi chemical industry leadership is intimately connected with our vision for economic and social development beyond physical products. Last September the nation inaugurated a remarkable new postgraduate research institution, King Abdullah University for Science and Technology, or KAUST. The university has enlisted numerous major corporate research partners – including Schlumberger, Boeing, Halliburton, and Dow Chemical as well as SABIC and Saudi Aramco.

The launch of KAUST accelerates efforts that have been going on for some time through higher education and specialised training to enhance the quality and quantity of opportunities for employment and economic growth in Saudi Arabia. Numerous other Saudi universities have endowed professorships and programmes in partnership with the hydrocarbons and chemical industries.

Specialised training institutions also support our strategy, as do the research and training centres of leading corporations operating in the Kingdom. Advances emerging from KAUST and other institutions will complement gains in intellectual property we expect from joint ventures of Saudi and international companies. Realising our nation’s strategic advantages as a global chemical hub, and reaching our further goals for development of intellectual and human capital, are vital to the citizens of Saudi Arabia. Our population is very young and is growing. Th is reality requires a high quality of education for our youth to support diversification of industries and the economy, and to provide jobs for the new generation. Because of this I want to emphasise the need for action to promote international trade.

International trade Petrochemical producers in the Gulf region export significant volumes of their products to other regions of the world – in fact to more than 100 countries. It is very important for our industry to have access to the world’s market unfettered by artificial trade barriers. There is a

concern that de-globalisation is a growing threat and could result in restrictions of world trade.

Most experts are in agreement that growth in global trade is beneficial to economic growth in most countries. Growth in global trade in prior years has been credited with lifting millions of people out of poverty in the emerging economies and bringing lower prices to consumers around the world. And yet, the World Trade Organisation’s Doha trade round has been languishing for over seven years as major country negotiators have been unable to reach consensus. This is in the face of an estimated 10 percent drop in merchandise trade volumes, according to WTO estimates. There are further

“Petrochemical producers in the Gulf region export significant volumes of their products to other regions of the world – in fact to more than 100 countries” complications to concluding a successful Doha trade agreement brought about by the recent recession. There have been significant job losses in many major countries, which encourages governments to protect domestic jobs and industries. Currently, there is a serious concern and some hard evidence that protectionism will gain strength, further depressing global trade as well as making it more difficult to complete a successful new WTO agreement. Gulf petrochemical producers are long-term players, aiming to deliver affordable products to world consumers. It is certainly in our interests to work to maintain open markets and to support efforts to re-energise the Doha negotiations.

Growth in global trade is in our interests as well as those of our customers around the world. Our region has long-term comparative advantages to be the world hub for petrochemicals production, and increasingly, the hub for more sophisticated downstream products. Neither the recession of 2008 nor any protectionist measures by parties outside the GCC region can

alter this fundamental reality. The Gulf region´s advantages are based on geography, natural resources, and an already well developed production, refining and chemicals manufacturing infrastructure. In this regard, it is strategically and economically in the best interests of GCC producers to develop and expand their domestic markets. A vibrant and growing domestic market that provides stability of demand, also reduces costs for transportation and mitigates the effects of trade barriers.

Building a skills base For sure, the near future will present some obstacles that will test our durability, commitment and management skills. In the Gulf we have a productive and trained workforce. We must continue to provide training to further upgrade and burnish the skills of this workforce, and we must look for ways to separate ourselves from competitors through innovation and development of proprietary technology and markets. The Gulf chemicals industry can and must redouble its efforts for environmental stewardship, corporate social responsibility, training and employing our own nationals, promoting R&D to support new technologies and small business development, and best practices in safe operations and corporate governance. These concerns are common to many other hydrocarbon processing industries beyond chemicals such as petroleum refi ning and gas processing operations, thus perhaps it would be time to consider broadening this very association to include these types of companies. It is my fervent belief that every step we take to improve our understanding of these concerns and our performance in addressing them will add not only to our reputation but also to our profits.

The end products of chemicals are things in which we can take pride: life-saving pharmaceuticals; packaging to make food safer and more accessible; durable and affordable materials for clothing and shelter. A world without today’s chemical products would be catastrophically poorer, less healthy, and more dangerous. May all of us in the industry renew our commitment to work together to promote sustainable growth, and to promote public awareness of the current and still-to-bediscovered benefits our industry offers for the quality of life.

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INDUSTRY INSIGHT

Streamlining your operations We hear from Bentley Systems’ John Sanins on how an integrated data-managed engineering solution can help meet the demands of the global oil and gas sector.

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oday’s global energy busiwithout compromising safety and environness environment faces mental considerations. significant challenges in These challenges can be addressed by the wake of downturns in employing an integrated data-managed engimajor industrial econoneering solution specifically designed to meet mies. Fluctuations in oil the demands of the global oil and gas sector. and gas prices have changed the scope and Bentley Systems’ oil and gas solution offers a amount of investment in capital projects. data-centric environment in which evolving Consequently, owner-operators now put more plant and related data are properly managed emphasis on increasing operational efficiencies using existing infrastructure while maintaining operation and production margins during low market demand. Paradoxically, worldwide demand for energy is projected to increase as much as 45 percent by 2030, led by emerging economies. The International Energy Agency (IEA) estimates that these economies will account for nearly 90 percent of the world’s energy demand over the next two decades. The factors that will drive this demand are population growth and mass industrialisation. Estithroughout the plant lifecycle, eliminating mates project global population will increase data re-entry, avoiding duplication, and imfrom the current 6.7 billion proving overall engineering to more than nine billion data quality and integrity. Th is people by 2050. It is also prenew approach to managing and dicted that millions of people reviewing lifecycle data can in emerging economies will eliminate unnecessary documove from the countryside ments during the engineerto urban centres. ing phase, shorten timelines, The scope, nature, and enhance the level and quantity complexity of today’s of data during handover, and current and planned improve access to the right John Sanins is Solutions Executive capital oil and gas projects information for operations. for Process Manufacturing at Bentley Systems. His prior present additional chalBentley’s latest Openexperience includes Technical lenges to plant owners and Plant applications are the core Director for Global Business Development at Intergraph; engineering contractors. set of applications in Bentley’s Head of Plant Design Products at AVEVA; and Senior Business Owner-operators’ capital oil and gas solution addressConsultant at IBM Global project timelines continue ing the growing demands of Services. Sanins holds a Master’s degree in Business Administration to shorten in an effort to today’s highly distributed oil and an honour’s degree in Mechanical Engineering. speed time-to-market. At and gas projects. By adopting the same time, engineering the ISO 15926 open informacontractors must reduce overall project costs tion model as its core data model, together and meet reduced project schedules with fewer with a dynamic collaboration platform, Openskilled resources. To accomplish this, they Plant enables plant owners and engineering must increase productivity while maintaining contractors to capitalise on their investments high engineering integrity and quality – all in plant data without the constraints imposed

by current propriety third-party applications and associated closed data formats. Bentley’s OpenPlant ensures interoperability with third-party soft ware and open and easy access of information to all parties.

Bentley’s oil and gas solution applications continue to be used and successfully deployed by major participants in the oil and gas industry worldwide. Plant owner-operators using

“The scope, nature, and complexity of today’s current and planned capital oil and gas projects present additional challenges to plant owners and engineering contractors” Bentley’s oil and gas solution have virtually eliminated unnecessary or redundant project documentation, reduced expenditures in managing and streamlining multiple data sources and, in many cases, are now seeing and capitalising on an immediate return on their soft ware investment. Engineering contractors who have deployed the interoperable applications have completed major capital projects within agreed upon project schedules, and often ahead of schedule. They have seen significant improvements in end-user productivity, design quality and overall project execution as a result of their integration between Bentley’s design authoring and analysis tools coupled to Bentley’s document and engineering content management systems.

The Bentley oil and gas solution offers both plant owner-operators and engineering contractors a comprehensive, scalable environment to create and manage project data and associated deliverables more costeffectively. In addition, it helps them achieve on-time project delivery with lower costs in application deployment, data creation, management and handover.

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EXECUTIVE INTERVIEW

Redefining wellbore physics i-TEC’s Espen Norheim lifts the lid on how its wellbore physics and innovative solutions have resulted in a portfolio of products and services.

i-TEC has developed a comprehensive product portfolio in a short period of time. What have been i-Tec’s primary drivers?

Espen Norheim. From the very beginning, part of the i-TEC identity was to provide early phase customer inclusion during the concept and engineering phase, alongside a rigid focus on optimising the project timeline from idea through to fi nished prototype testing. By establishing and maintaining a close dialogue with the end users and application experts, our team of inventors and design engineers can develop fit for purpose solutions that deliver as per specification and expectations quicker. The i-Tec team are experts in mechanical and hydraulic design, whilst our customers are the true application experts.

The reasons why we have matured quickly as a company is because of the close cooperation with our customer, from the idea phase to a qualified product.

So with products in place, you were ready to go to market?

EN. Some homework had to be done. In April 2008, i-TEC established an office in Aberdeen, UK, followed by one in Houston in July of the same year. At the same time, the business gained its NS-EN ISO 9001:2000 certification and also obtained an Achilles qualification. Then in June 2008, i-TEC moved into its new headquarters in Stavanger. To provide an integrated solution, we merged with PetroTools and Arctic Technology to form i-TEC Well Solutions at the start of 2009. Internally this move made a lot of sense and the main advantage that we have observed so far is that we now operate one team of highly efficient development and field engineers from each company.

From a customer perspective, it is clear that our efficient working practices mean we can meet tight deadlines, while assisting them with their development and fabrication of well equipment.

During the fi rst half of 2009, we established operations in the Middle East, an office in Bahrain serving Saudi Arabia, and then another one in Dubai looking after the other main Gulf states. Now our main focus is taking the products and solutions that we have fi nalised and getting them out into the market. Our core focus will remain in the

regions where we have already invested in infrastructure. These are the UK, Northern Europe, the US and the Middle East. We are now in contact with customers in these locations and have built up local technical support, which is crucial for our success.

From a customer perspective, can you provide an example where i-Tec has made a difference?

EN. The i-VALVE is a good example of how we have positioned ourselves to offer a unique product. As oil and gas companies expand their operations, they require bespoke equipment for their wells and as such cannot rely completely on the major catalogue companies that are supplying high volume completion equipment. As we provide dedicated skills and resources to match customer requirements directly to form individual products that are tailored to their unique applications, this way we are able to fi ll the gap in the market when it come to completion equipment.

We were contacted by BP regarding this service and in a matter of two-and-a-half months we were able to design, third-party test and fabricate a full set of i-Valves, which is obviously not a timeline that the largest suppliers can compete with.

The advantage of this product is that it’s not just an ordinary valve; it can carry out a variety of jobs, and it can also operate with high differential pressure.

Where is i-Tec going next?

EN. Looking ahead, I would like to see i-Tec build its brand and reputation to become the primary contact when operators have issues with their wellbore physics, or when pressure and flow needs to be balanced and managed, as we are well-equipped to deal with those kinds of challenges. The i-Tec team are experts in mechanical and hydraulic design, whilst our customers are the true application experts.

Espen Norheim’s professional career started within R&D in the field of computer science. He then moved into project management for Autronica Oil & Gas, delivering topside safety systems. In 2005, he was appointed Global Sales Manager for Autronica Oil & Gas, overseeing worldwide sales. In 2008, he accepted the Managing Director position for i-Tec AS.

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SPECIAL REPORT

UNTAPPED

With Iraq pinning its hopes on its mammoth oil and natural gas reserves to fund the state’s road to recovery and a more prosperous future, we assess the country’s potential and how the IOCs will play their part in unlocking the black gold.

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or a war-ravaged country like Iraq the petro-dollars generated from its enormous hydrocarbon reserves are the key to raising the nation from its knees and the road to a brighter future. Oil accounts for a whopping 85 percent of government revenue but the country is pumping far short of its true potential following decades of sanctions, wars and tyrannous rule. The ramshackle oil sector produces around 2.4 million barrels a day (bpd) in a land that perhaps is the most under-exploited in the world. Iraq’s official reserves are around 115 billion barrels but this figure is based on outdated 2D seismic surveying. Ambitious estimates by industry insiders triple the outdated reserve figure, partly because only around a quarter of the 80 known fields have been significantly tapped for oil. Some experts suggest the Western Desert alone could hold as much as 100 billion barrels.

If these estimates turn out to be true, Iraq would spring to the top of the global production league, ahead of neighbour Saudi Arabia. “The reserves are not exaggerated – they are huge, and I am optimistic that this figure will be higher than 115 billion barrels,” suggests Manouchehr Takin, Senior Analyst at the Centre for Global Energy Studies. “Some think it

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could be 200 billion or higher but these amounts are just estimates.” With rock-bottom extraction costs, thought to be as low as US$2 per barrel, and more than a third of reserves lying just 600 metres below the earth’s surface, it’s clear why the oil majors are so desperate for a slice of the pie. It’s a tantalising prospect, according to Takin: “Why go to harsh and unhospitable places in the world like the Arctic? It really is entering the unknown and for all the costs that are incurred, you are not guaranteed to find oil. In Iraq the costs are low and the fields are already there.”

After much wrangling over how much foreign firms receive for each barrel of oil they extract, the government has signed 10 TSCs, with the 11th in the late stages of ratification, with the likes of BP, CNPC, Shell, Sonangol, LUKOIL, and ExxonMobil. BP and CNPC having landed the technical service contract (TSC) to tap the elephant field Rumaila and its 17 billion barrels of known reserves. Targeted production is eventually 2.85 million bpd but by the end of the year BP and CNPC are aiming for increasing output by between 100,000 and 150,000 bpd. Shell and ExxonMobil have the TSC for the 8.7 billion-barrel West Qurna-1 field which has a target of 2.32 million bpd. All foreign firms have production plateaus that need to be hit as part of their TSCs. For now, the IOCs are ramping up early planning and

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POTENTIAL preparation work for their mega-projects in the south, preparing the ground for worker camps, tendering early work contracts, and consolidating liaison contacts with Iraqi state-owned oil company personnel.

Even hard-line nationalists who accuse foreign firms of plundering Iraq’s energy resources are aware that the dilapidated oil industry needs foreign investment, technology, know-how and manpower to get the petro-dollars flowing. Likewise, many of the refineries and pipelines have been sabotaged or damaged since 2003. “I would say the oil industry is on its feet at the moment but the question is what needs to be done to get it to a brisk walk?” says Timothy Mills, former President of the American Chamber of Commerce in Iraq. “Iraq needs to rehabilitate refineries, explore new reservoirs and then extend the pipeline and port capabilities in order to export, so the IOCs will be key because this needs significant investment.”

Lofty ambitions By developing new and existing fields Iraq’s oil minister Hussein AlShahristani has ambitious plans to eventually boost production to somewhere between 10 and 12 million bpd. In the medium term Iraq pledges to be churning out 4.5 million bpd in three years and six million bpd seven years from now. Some experts question whether much, or any, of these goals are really achievable. “The large number of mega-projects in a limited geographical area is bound to make the contracting industry overheat, and even ,” says Samuel Ciszuk, IHS Global Insight Middle East Energy Analyst. “In fact, from a global supply and demand perspective that might well be a much better outcome for all producers, including Iraq.” Reaching

six million bpd is thought to require upwards of US$50 million of investment in the industry.

Likewise, Thamir Al-Ghadhban, former Iraqi Minister of Oil and Chairman of the Advisory Commission at the Prime Minister’s office, told the media recently that he didn’t believe his country could hit anything close to the 12 million bpd being touted due to logistics and socio-political factors. His opinion is that possibly eight million bpd could be achieved in seven years.

“Reaching half of Iraq’s output target in seven years would be a feat worthy of celebration” Samuel Ciszuk, IHS Global Insight

He also suggested domestic consumption could hit one million bpd by then.

Despite the doubt that shrouds production targets, oil exports reached 2.069 million bpd recently – their highest level since Saddam Hussein’s invasion of Kuwait, oil spokesman Assem Jihad told AFP recently. The target is to achieve 2.15 million bpd this year. Dramatically raising production will generate hundreds of billions of dollars a year, depending on the price of oil. Even at today’s production rate of 2.4 million bpd, the government is earning US$170 million every 24 hours.

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This level of income is vital for a battle-scarred Iraq and its new government elected after the country staged the second full parliamentary election since the US-led invasion in 2003 to topple Saddam. For starters, most of the oil and gas infrastructure is in a decrepit condition, which will need to be addressed urgently according to Ciszuk. “The Oil Ministry will have to tender repairs and upgrades, particularly to its pipeline network, very soon as its current spare capacity in the south hardly even matches this year’s gain. As oil production continues to rise during the coming year, the expansion of Iraq's southern oil export terminals will also become urgent, stretching the state industry’s already extremely depleted project management capabilities.” Then there is the widespread corruption that infects the country. Indeed, since Saddam’s regime fell Iraq has gained the dubious honour of becoming one of the world’s most corrupt countries, alongside the likes of Somalia and Myanmar. On top of this, there is still no concrete hydrocarbon law – a bone of contention between political factions for years.

A tale of two cities But while Baghdad has struggled to get its house in order and rubber stamp deals with the IOCs during protracted bidding rounds, semi-autonomous Kurdistan in the north has been quite happily working with overseas oil companies to extract hydrocarbons, much to the anger of Al-Shahristani, who has branded these deals as “illegal”. Iraq’s government and the Kurdistan Regional Government (KRG) continue to be at loggerheads over who controls the vast reserves the region holds. The row has been running throughout the past government’s tenure, keeping oil exports from the region’s two developed oilfields – Sinopec and Genel Enerji’s Taq Taq and

DNO's Tawke – shut in since they were initially brought onstream almost three years ago. “The KRG for its part cannot back down, as it has been highly successful in attracting IOCs to its acreage,” suggests Ciszuk. “Indeed, as exploration has begun the acreage has proved to be more prolific than many initially thought. While exploration investment for the programmes to which the IOCs have committed still seems solid, companies could soon start to baulk at investing in the development of their finds, unless there is a sign of some form of compromise opening the way for them to export and monetise the crude from their oilfields.”

The city of Kirkuk is the country’s northern oil hub with current production from its giant oilfield producing 450,000 bpd. Production could eventually hit one million bpd, while this region is also Iraq’s sole oil pipeline route into Turkey. As well as the dispute over the contacts signed between Kurdistan and foreign energy firms, Ciszuk says the manner in which Iraq and Kurdistan have gone about attracting IOCs have been very different: Kurdistan has opted for production-sharing agreements (PSAs) while Iraq has offered TSCs. The PSAs Kurdistan has with IOCs have come in for a fair amount of criticism, however. Al-Ghadhban told reporters in March that the agreements were “inferior in terms of preserving the interests of Iraq” compared to the contracts signed pre-regime change.

Taking precautions With the oil supermajors poised to flood into Iraq, lingering security concerns continue to dog this fragile country. As was expected, the March elections sparked a surge in suicide attacks and car bombings. Although the level of violence is a far cry from a few years ago, protecting employees from attack,

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and even kidnappings, will be of paramount concern for IOC bosses. Toby Chinn, Associate Director in Iraq for security consultants Control Risks, told O&G that the risks differ considerably depending on where you are in the country. “The risks vary hugely – the situation in Basra is very different to Baghdad, while the risks at the Ramaila oilfield is very different to West Qurna.” This impacts how the IOCs allocate their funds, says Chinn. “So while it may be appropriate to use armoured vehicles and armed guards in one location, there may be a more effective way in another, such as journey management, communications and community relations programmes.” This sentiment is echoed by Mills: “You have to analyse it on a case-by-case basis and you structure your business plan accordingly with respect to your security precautions and security costs,” Chinn and his team have years of experience and local knowledge on the ground in Iraq; they are the eyes and ears for the IOCs. And it’s not just security risks that he has to advise companies on – there are political risks, contractural risks, risk to reputation and physical dangers to consider.

However, he says many foreign energy firms can draw on past experience from operating in some of the world’s danger zones. “The principles and spectrum of risks are the same irrespective of the environment but a lot of oil companies already have experience of working in places like Nigeria or Yemen.” Control Risks has also received requests for long-term risk assessments on neighbouring Iran and its frosty relationship with the US. “Iran has the capacity to interfere in Iraq so if the relationship changes and there is a hostile confrontation this could jeopardise or present more political risk to oil contracts awarded in Iraq.”

Despite all these fears and logistical headaches, the rewards in Iraq are too juicy to pass up for foreign companies. Iraq’s problems won’t be solved overnight but the new government is all too aware of the need to plough on with addressing massive logistical, infrastructural, financial and management challenges, according to Ciszuk. He adds: “The promise of huge

Oil Minister Hussein Al-Shahristani is bullish about Iraq’s production targets, contrary to analysts’ predictions oil company investments in its main fields has swayed many resource-nationalist sceptics, tentatively setting the scene for more cooperative political relationships in the energy sphere.” But it won’t be all plain sailing, he suggests. “With the ambitious schedule looking likely to slip, a host of new tensions and challenges should be expected as early as the end of 2010.” n

IRAQ’S 11 SIGNED TSCS Oilfield

Current Output (or first production target; b/d)

Targeted Plateau Production (b/d)

Known Reserves (bil. bbls)

Remuneration Fee (US$/b)

Developer

Rumaila

1,000,000

2,850,000

17

2

BP and CNPC

Zubair

195,000

1,200,000

4

2

Eni, Oxy, KOGAS

West Qurna

279,000

2,325,000

8.7

1.9

ExxonMobil, Shell

West Qurna-2*

(120,000 end-2012)

1,800,000

12.876

1.15

LUKoil, Statoil

Majnoon

45,900

1,800,000

12.580

1.39

Shell, Petronas

Halfaya

3,100

535,000

4.098

1.40

CNPC, Petronas, Total

Najmah*

(20,000)

110,000

0.858

6

Sonangol

Qayarah*

(30,000)

120,000

0.807

5

Sonangol

Gharraf*

(50,000 –by 2012)

230,000

1

1

JAPEX, Petronas

Badrah*

(15,000)

170,000

0.15

5.5

Gazprom, KOGAS, Petronas, TPAO

Maysan/Missan**

100,000

450,000

2.5

2.3

CNOOC, Sinochem

* Non-producing ** Still to be ratified by government Source: IHS Global Insight www.ngoilgasmena.com 83

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ASK THE EXPERT

The importance of filtration Aykut Selcuk looks at the significance of filters in the production of crude oil, both on and offshore.

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he production of petroleum oil is basically a very simple process – a hole is drilled down into the earth’s crust, until an oil-bearing rock formation is reached, whereupon the oil is forced up the drilled hole to the surface. The consequent ‘gusher’ is a familiar sight to moviegoers. But the actual process is a good deal more complex than this. Somewhere along the line the importance of filtration for more efficient petroleum production comes in. The oil recovery processes involve large flows of liquids and gases, most of which have essential needs for filtration and sedimentation to separate oil from water, and liquid or gas from solids. The most important liquid flow is, of course, the crude oil transported up the well bore for treatment at the surface.

The recovery of crude oil from underground requires separation treatment in two main places: at the well bottom, and at the well head. In the very restricted space at the bottom of the producing well, solid/liquid filtration is necessary to prevent the passage up the well pipe of as much suspended solids as possible. This is done by the well screen, a zone of perforated material that is either built in to the end of the well pipe, or fitted as a sleeve over a very coarsely perforated part of the pipe. The well screen is a specialised form of filter and is, of course, used for water production as well as oil. It can be made from wire mesh, wire wound, perforated plate or porous metal fibre material. The prime objectives of this

Aykut Selcuk is Managing Director at Armada Offshore. Despite his parents both being lawyers, he decided to pursue a career in a different path. After finished his Bachelor's degree in Communications (Journalism), he moved to the USA to study computer technologies. He was later named the youngest Managing Director in Armada and has now shifted his focus to filtration technologies.

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stage of filtration are to prevent blockage in the well pipe, and to protect whatever pump is being used down-hole to carry the oil to the surface. Perforated screens and woven wire meshes provide a more accurate and consistent aperture than does a mat of nonwoven metal fibres.

Once the oil reaches the surface, there is more working space for any required filtration, and the major separation requirement is to recover the crude oil from its mixture with the produced water. Production economies dictate that this separation should be as efficient as possible, since the separated water may be going to waste, carrying any unseparated oil with it. In the liquid/liquid separator a further amount of suspended solids will also be separated, and this may be

“I believe the oil production process is a good market for filtration and sedimentation equipment” sufficient solids removal to enable the separated oil to be transported to its ultimate refinery destination without damage to the transporting system. If not, then further filtration will be necessary at the well head, although the flow rates will be high, and the filters will have to be automatically cleaned.

On the other hand, natural gas produced in association with crude oil will not normally present a filtration problem – from solids at least, although it may need separation from oil or water droplets. However there is nowadays an increasing need for the injection of gases into underground strata, to improve oil production rates. This can be into the gas cap over the reservoir – when the need for filtration is low, or directly into the rock formation as an enhanced oil recovery process. The direct injection of gases will require that they be free from suspended solids, possibly down to the same size level as is the case for water injection. This will be done in the same sort of filters as are used for engine intakes, using Vblock minipleat filter panels for more efficient results. In conclusion, I believe the oil production process is a good market for filtration and sedimentation equipment. Although some parts of it – the primary production – are relatively mature, others, in particular tertiary processing and recovery from tar sands, still have major growth ahead of them. n

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INDUSTRY INSIGHT

MAXIMISING RECOVERY David Baley on the important role adaptive Inflow Control Device (ICD) technology plays today.

T

he production benefits of using ICD technology are now widely appreciated in the industry. The understanding of limitations are improving with key deployment concerns such as fluids management, a particular point of focus. The industry is now moving to a more adaptive type of ICD (no longer strictly a passive technology system) combining ICDs with other completion techniques and technology further augmenting benefits realised over the past 10 years.

ICDs cause a pressure drop within an open hole completion to regulate fluid flow in order to create an even influx from the well or even flow distribution of injected fluids. The correct application of ICDs can delay the onset of water and gas production and optimise reservoir management, ultimately improving hydrocarbon recovery. In addition to these benefits, ICDs can also improve the reliability of sand control and aid well clean-up. Unlike other open hole completion types when using ICDs fluid transfer between the completion bore and the reservoir/completion annulus occurs at a single point, within each ICD unit. This provides scope for introducing technology to enhance the functionality of ICD completions.

Maximising benefits, specifically improving performance in the more common but less homogeneous reservoirs has become a real possibility. Improving wellbore clean up, without resorting to excessive drawdown or clean up rates is another real possibility. These systems benefit from combining technologies and the latest adaptive ICDs are delivering additional advantages previously not realised in individual (passive) ICD flow regulator design. This has

David Baley is the Business Development Manager of Petrowell Ltd. A graduate of TCU in Ft. Worth, Texas, he has worked in the industry internationally for over 30 years, with the last nine years focusing primarily on open hole completions.

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allowed the industry to reasses the original flow regulator design and increase it’s impact and viability in gas, injector and heavy oil applications.

Applying these combined technologies results in an improved drainage profile and uniform flow along horizontal wellbore sections. Horizontal wells are an established method for hydrocarbon recovery. In formations that can be completed horizontally, the wellbore offers a greater contact area with the productive layer, allowing lower drawdown and maximising hydrocarbon recovery. In homogeneous formations, as the length of the horizontal section increases, its resistance to flow increases – in the form of fluid flow friction effects, generating a higher pressure drop at the heel, compared to that at the toe. This occurrence will eventually lead to premature water/gas production.

In heterogeneous or fractured formations, this process can be greatly accelerated by high permeable formations or fractures. This invasion will greatly impair the overall well performance and recovery.

Adaptive ICDs are designed to help evenly distribute the inflow throughout a horizontal wellbore. The devices reduce the tendency of early water or gas production, allowing the reservoir to drain more efficiently while maximising production and recovery. Other benefits include compartmentalisation and long-term flow management, elimination of wash pipe and associated handling difficulties, extending the well life expectancy, improved NPV and enhanced mechanical integrity. There is an anticipation that the growing ICD penetration in the injector market will continue to gain momentum, obviously on the back of recent successful deployments. The number of ICD deployments are predicted to increase perhaps to the extent that, in combination with other tools, they could represent a major shift change in the traditional intelligent completion market in highly leveraged wells on land, sea and perhaps even deepwater. n

“Maximising benefits, specifically improving performance in the more common but less homogeneous reservoirs has become a real possibility”

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PROJECT UPDATE

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Rebirth of Rumaila

Just to the south of the fertile lands of Al-Qurnah, the meeting point of the Tigris and Euphrates rivers, and 60 km west of Basra in south-eastern Iraq lies a stony desert with a bleak landscape that is decorated only by oases of small shrubs, isolated sand hills and dry river beds. However, underneath this wasteland lies Iraq’s biggest treasure – the supergiant Rumaila field, estimated to contain 15 percent of the country’s oil reserves. Maxim Lyashko reports.

R

umaila’s turbulent history started over half a century ago when it was discovered

by Basra Petroleum Co. in 1953. Since then the development of the field has been closely linked with Iraq’s transformation into the world’s major oil producer and exporter as well as with the country’s infamous war confl icts in the not so distant past. Oil production at Rumaila started just a year after its discovery at a rate of 20,000 barrels per day (bpd) and reached its peak of about 1.6 million bpd in 1980, which represented an astonishing 45percent of Iraq’s total output that year. However, the subsequent history of oil extraction at this field had a cyclical nature due to numerous military confl icts starting with the Iran-Iraq War, during which the production from the field was completely halted. Moreover, it was Rumaila that became one of the main reasons for Iraq’s invasion of Kuwait who were accused of using directional drilling technologies to pump oil from underneath the border and allegedly stealing US$2.4 billion worth of Iraqi crude. Finally, it was on this oilfield where the last battle of the Gulf War took place in 1991.

Bearing strategic importance to Iraq’s economy, Rumaila was the fi rst field in the country to restart production after the Gulf War; however, subsequent years of UN sanctions, post-2003 violence and long-term underinvestment in Iraq’s petroleum sector took their toll on the field’s development. Even water injection system projects at Rumaila, which were part of US-directed aid programmes aimed at the reconstruction of Iraqi oil sector in the 1990’s, have not resulted in the expected

improvement, and for the past two decades Rumaila remained damaged from over-drilling and poor reservoir management.

Now all that is about to change after BP and its partner China National Petroleum Corporation (CNPC) won the right to develop the field in a historic televised auction in June 2009 and later in November of that year it formally signed a 20-year technical service contract – the first long-term oilfield development contract of the post-Saddam era.

The workhorse of Iraq’s oil industry It seems that Rumaila is as important to Iraq as it is to BP. The British oil major helped to discover the field back in 1953 and gained further information on its structure through a reservoir study contract awarded by the Iraqi Oil Ministry in 2005. This early interest by BP is not surprising – Rumalia is among the world’s last remaining pockets of so-called ‘easy oi’, meaning that it does not require expensive ultradeep drilling or pioneering production techniques. Its estimated recoverable reserves of 17.77 billion barrels are larger than the total proven oil reserves of China, Qatar or Algeria.

So it is no wonder that BP has agreed to develop Rumaila without getting an ownership stake in the field while also accepting the government’s low remuneration fee of only US$2 per barrel once the production has been raised by 10 percent from its current level.

The Rumaila field is an 80 km long anticlinal structure that was found to be trending from south to north and historically divided into two parts. “When Rumaila was discovered it was believed to be a single domal structure

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confined to the south of extensive marshland to the north,” explains Michael Daly, Group Vice President for Exploration at BP. “This area later became South Rumaila as prospecting moved northwards and discovered the North Rumaila continuation in 1961.” The total reserves of North Rumaila are estimated at some 31 billion barrels with only just over three billion barrels produced so far. This section has three reservoirs in development including the Mishrif limestone, Upper Zubair sandstone and the heterogeneous Nahr Umr Formation. Mishrif is the biggest reservoir in North Rumaila accounting for over 70 percent of its reserves. The South Rumaila section is thought to have 30 billion barrels, but because of the inclined nature of the formation it has so far produced three times more oil than its northern part. There are four reservoir units that have already been appraised and produced from and which are distributed between the Mishrif and Zubair formations.

The Zubair reservoirs are the Upper Shale and Upper Sandstone (collectively known as the Main Pay) and Lower Sandstone members.

Currently, according to Daly, the volumes are well-described only in the Main Pay and Mishrif reservoirs. “Other reservoirs still require

Excess gas is burned off at the Rumala oil field

achieved in 1980, but still accounted for almost half of Iraq’s annual oil production. The consortium led by BP (38 percent) with partners CNPC (37 percent) and State Oil Marketing Organisation, the sales arm of the Iraqi Ministry of Oil (25 percent), has agreed to nearly triple the Rumaila field’s output to 2.85 million bpd in only six years. Th is would make it the world’s second largest producing oilfield after Saudi Arabia’s Ghawar and would alone lift

“Rumaila is clearly a brownfield development with a huge amount of kit in the ground and on the surface.

This fact has important implications for our confidence in our ability to reach the initial production target”

significant definition before a definitive volume can be determined,” he says. “Suffice to say the volume is large.” Moreover, there are additional hidden treasures for BP. First, there are discovered but undeveloped reservoirs – Nahr Umr, Upper Shale Member, Yamama, Najma, Alan and Mus/Adaiya in North Rumaila and Lower Fars, Nahr Umar, Fourth Pay and Yamama in the South. Second, there are the undiscovered potential reservoirs that the consortium can explore and develop over the course of their 20year redevelopment project.

Path to recovery At the end of 2009, the struggling field was producing approximately one million bpd, which is far from its potential and the peak

Iraq’s total oil production capacity from about 2.5 million bpd to 5.35 million bpd.

The 20-year contract, however, comes with a spending commitment of US$15 billion.

The first stage is the 33-month remedial programme involving three steps starting with a halt to any non-optimal operations that Iraqi oil engineers had to revert to in past years, often due to the lack of other options; then arresting the production decline; and fi nally achieving a sustainable and improved production rate of 10 percent above the initial rate prevailing at the start of the contract. BP is looking to spend a minimum US$300 million in order to carry out the appraisal programme including acquiring, processing and interpreting 1500 square km of 3D seismic survey over the two

fields’ area and preparing the much needed geological and reservoir engineering studies and 3D simulation for the reservoirs. The most important objective for BP is achieving an improved production target rate, since it will be able to recover its costs and receive US$2 billion worth of oil once this initial incremental production is brought on stream. “The current infrastructure in place on the field consists of over 800 wells – over 550 producers and more than 150 injection wells – feeding 10 gathering and degassing centres,” says Daly. “Just over half of the producing wells are flowing today; but it is the wells that are not flowing where the short-term oil opportunity lies.”

Since the Rumaila service contract entered into effect on December 17, BP hasn’t been wasting time – in January the consortium held the first joint management committee meeting and decided on a US$1.7 billion budget for 2010 with the target to add between 150,000-200,000 bpd by December 2010. On top of that, 10 firms (including Halliburton, Schlumberger, Baker Hughes, Weatherford, Iraq Drilling Company as well as companies from China and Turkey) were invited to drill 56 new wells and do workover projects on 30 others. Currently, the field has 10 rigs (six belonging to Iraq Drilling Company and four to Weatherford and Akkad). BP’s plan is to add five new rigs this year and another 10 in 2011. The consortium is also looking to drill 200 additional wells next year to pump output at Rumaila up to 1.5 million bpd. This rehabilitation and expansion project is managed by the Rumaila Field Operating Organisation (ROO) staffed mainly by employees from

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Work continues at the Rumaila oil field in 2009

South Oil Company (field’s original operator) and a small number of technical experts and managers from BP and CNPC. “The job BP has now taken on is to work with the South Oil Company and our partners to renew investment in the field and to bring new and innovative technology with the singular intent to grow production beyond the previous peak; sustain it for several years; and in doing so increase the expected recovery factor of Rumaila”, explains Daly. “Rumaila is clearly a brownfield development with a huge amount of kit in the ground and on the surface. This fact has important implications for our confidence in our ability to reach the initial production target.”

The BP solution BP’s development plan starts with a focus on securing the base production from both the Main Pay and the Mishrif reservoirs.

Daly continues: “A full field surveillance programme will be established on the existing Rumaila well stock. From our earlier work we have more than a year’s work of well workovers already identified, largely involving the addition of electric submersible pumps (ESPs) to improve well deliverability and workovers of the old wells.

Longer term we will enter the enhanced redevelopment phase, which will grow the well stock through a major drilling campaign, eventually deploying 20-25 drilling rigs and a number of workover rigs. This early work will focus on the Main Pay reservoir and also start the full field development of the Mishrif. The Main Pay will be the main story in the early years; the Mishrif peak will follow and sustain the field. Th is will be accompanied by a field-wide waterflood campaign to maintain field pressure.” According to Daly, BP will

use a number of its proprietary technologies, including its smart field or Field of the Future technology to provide real time management and remote monitoring of wells; Bright Water injection of a polymer to help improve the efficiency of water flooding; and POWERlift ESPs which will allow for downhole repair and replacement. But in addition to refurbishing the production plants and the water injection facilities, another important task BP is facing is to fi rst supply all 12 production units and 10 water injection plants in North and South Rumaila with an internet connection.

BP has a lot of experience of taking on brownfield developments, so Daly is confident in achieving ambitious targets set by the contract. However, there are a number of key challenges. “Regionally several large development issues remain such as access to sufficient water for large water flood projects, gas capture and utilisation and sufficient export ullage for the oil production growth”, he explains. “A number of logistical issues could also impact the pace of development.

There will now be 10 developments competing for resources; skilled people, oil field services etc.” Despite these challenges, which are currently being addressed by the consortium, Rumaila is fi nally entering the 21st century after over 50 years in development.

Iraq is currently the world’s eleventh biggest oil producer, but the invitation of foreign oil majors with their cash and expertise and the rehabilitation of its supergiant oilfields give it the potential to climb to third place or higher, rivalling Russia and Saudi Arabia. An increase in production to just over four million bpd in the next five years will also pour approximately US$1.7 trillion into the country’s battered economy and would fi nance major infrastructure projects across Iraq. Both BP and CNPC see rejuvenation of Rumaila as a key step in the post-war reconstruction of the country, and with such remarkable history this field is without doubt going to play a crucial role in Iraq’s future.

Dr Michael C Daly is Group Vice President for Exploration, BP, responsible for the renewal of BP’s oil and gas resource base, which includes accessing new resources, identifying new areas of exploration potential, and leading the company’s exploration drilling programme.

He began his career as a field geologist in the Geological Survey of Zambia, later joining BP as a structural geologist in the mid-1980s. Prior to his appointment as the head of exploration, Daly was BP’s President of Middle East and South Asia.

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INDUSTRY INSIGHT

A SCIENTIFIC

APPROACH Daniel Hitzman says ‘3G’ microseep surveys offer a new formula for exploration and development success.

S

earching for oil and gas deep underground requires discreet detective work: sift ing through all the clues and data must be painstakingly and carefully considered. And even then it might be the very smallest molecule of evidence that is critical. That is the state of petroleum exploration and development today – sometimes the very smallest molecules are the key to guarantee success.

Micro is the new macro Observing visible oil seeps at the surface – like outcrop stains or oil slicks on water – builds huge confidence that hydrocarbons are present in a basin or block area. Historically, parts of many MENA basins were fi rst targeted because of these visible surface macroseeps.

However, macroseeps reveal only part of the seepage spectrum story and fail to offer strong location clues since they escape along larger fault conduits. But hydrocarbon microseeps of light hydrocarbon gases are now being used to

more accurately locate oil and gas reservoirs at depth. These microseep gases may be invisible to the human eye, but to gas chromatographs and natural microbial cultures they are clearly discernible and are very potent indicators of hidden reservoirs with chimney signatures.

Very small and very buoyant molecules of light hydrocarbon gases – methane, ethane, propane, butane and C5+ – naturally escape from oil and gas reservoirs and penetrate permeable reservoir seals. All reservoir seals, even shales and salts, can be penetrated by these tiny treasures. These C1 - C5+ gases travel vertically through micro fractures up to the surface atmosphere forming a dynamic and measurable gas chimney signature. There are many seismic data sets that confirm such active gas chimneys. These direct indicator gases can be measured at the surface in both soil and offshore sediment samples.

The ‘3G’ approach Expensive geophysical data often determine where a prospect or development well is

to be drilled. Such seismic data are imperative for making these structural interpretations.

Unfortunately, disappointing dry holes tell us that not all seismic traps contain hydrocarbons. As an industry we still drill an unacceptable – and unnecessary – number of dry holes.

We must improve our exploration accuracy and optimise our development programes.

The combination and full integration of geology with geophysics and geochemistry– the new 3G strategy – is leading us to additional discoveries and more accurate wells.

Microseepage surveys are very precise tools for reconnaissance observations and for ranking seismic prospects. Detailed microseep signatures have been shown to reflect original reservoir heterogeneities before drilling and also accurately track dynamic reservoir pressures as production matures. Many more offset and in-fi ll well locations must be executed in our maturing reservoir assets – drilling where we have already discovered reserves.

Microseepage surveys are ideal to identify reservoir compartments and alternate zones

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for mature asset operators. Using such fast, low cost, and efficient microseepage methodologies allows operators to test for and squeeze out more reserves where 3D seismic is not practical nor affordable.

Stratigraphic detectives As structures become more and more scarce, we must look ahead for more subtle stratigraphic traps as future reserve builders.

MENA basins are very much under-explored from a stratigraphic trap point of view. Our extensive seismic database has previously focused on fi nding structures and thus leaving stratigraphic prospect interpretations under-utilised. Just as some explorationists are ‘mining’ old log library data for by-passed pay, old seismic data sets can be carefully reexamined for stratigraphic potential using microseepage surveys as lead indicators. Such 3G integration will breathe new life into mature provinces. Microseepage surveys will soon be the preferred exploration tool for discovering stratigraphic reservoirs.

Knowing natural seeps Microseep surveys are very flexible in their design and scope. This translates to great efficiency and low cost. Microseep surveys commonly follow seismic programmes and rank their numerous structural prospects.

samples, sample densities, and sampling patterns are specifically matched to the exploration programme and expected targets. For reconnaissance surveys a single-vehicle crew can complete over 65 linear kilometres in one day. Sampling densities generally range from 100 metres (development drilling situations) to 500 metres (reconnaissance delineations).

By design the collection methodology is very robust and extremely efficient. Men on foot with shovel/augers, and GPS create no environmental issues.

Little things, big results For the last 25 years, Geo-Microbial Technologies (GMT) has progressed to become the premier microseepage provider. GMT conducts hydrocarbon microseep surveys throughout MENA and the rest of the world – both on and offshore. GMT collects shallow soil and sediment samples and then uses two hydrocarbon microseepage detection methods: the Microbial Oil Survey Technique (MOST) and Sorbed Soil Gas (SSG). These microseep tools were first investigated by Phillips Petroleum Company and then further developed by GMT. Working with small and large independents, integrated majors, and NOCs, GMT has successfully integrated microseep data for selecting commercial discoveries (over 70 percent) and predicting dry holes (over 80 percent).

“The combination of microbial and sorbed soil gas surveys is the strongest, most integrated and cost-effective microseepage exploration strategy available” These post-seismic surveys help focus limited drilling budgets and avoid wasteful dry holes.

In MENA basins large-scale reconnaissance surveys – sampling expansive frontier areas prior to expensive seismic shoots – are also conducted. In mature producing areas, more detailed sampling patterns to locate by-passed reservoir compartments, offset well locations, and help plan waterflood and in-fi ll drilling projects are completed. The number of

A MOST survey tests for specific microbes which consume thermogenic microseep gases.

These natural microbial signatures are very reliable and reproducible and serve as excellent vertical seep locators. To distinguish whether the reservoir source is oil or gas or condensate, GMT supplements the microbial MOST measurements with Sorbed Soil Gas (SSG) analyses. These SSG tests are conducted on leftover and preserved MOST samples or from

separate and sometimes deeper samples. SSG results are measured in parts per million and the gas ratios are excellent indications of reservoir source. The combination of microbial and sorbed soil gas surveys is the strongest, most integrated and cost-effective microseepage exploration strategy available. Offshore analyses are completed on seafloor sediment samples (gravity or piston core samples).

Discover and recover Besides hydrocarbons, oil and gas reservoirs are also home to vast microbial populations. These microbes do not reflect reservoirs as part of the microseepage chimney signatures. They live in the reservoir feeding on carbon sources and multiplying – always multiplying. In some respects, this causes a reservoir to act more as an immense bioreactor rather than as a simple ‘container’ for oil and gas. As production engineers realise, some microbial activity is good and some is very harmful to production practices. The huge expenditure for biocides for H2S and sulfide control is testament to the efficacy of microbial growth. So why not make microbes work for enhanced production rather than against it?

GMT and its subsidiary, The LATA Group, provide for the manipulation of reservoir ecosystems and offer select formulae of nitratebased treatments which will allow beneficial microorganisms to outcompete detrimental microorganisms. Beneficial microbial populations will control and prevent reservoir souring and corrosion, as well as create an in-situ IOR ecosystem including surfactant, CO2 and acid production.

The world of petroleum offers many enticing clues. As exploration detectives we have seen budgets stretched and tolerance for dry holes rejected. The adoption of low-cost microseepage surveys obviously increases drilling accuracy and efficiency. The ability to discover stratigraphic reservoirs and optimise mature fields boosts microseepage acceptance. 3G integration will expand advanced exploration and production projects.

Daniel Hitzman is the President if iGeo-Microbial Technologies, Inc. Raised in Oklahoma surrounded by oil and gas, Hitzman received his geology degree from Carleton College. Since 1985, he has supervised all GMT service operations and travels worldwide completing geochemical exploration surveys. He has authored 30 papers and presentations for the petroleum industry as an AAPG, SEG, and SPE member.

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COUNTRY PROFILE

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It is the poorest country in the Arabian Peninsula and relies heavily on oil production for its economic survival. But with output set to stop in 2017, what does the future hold for Yemen? O&G reports.

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s the world’s 36th biggest oil producer Yemen lags far behind its MENA neighbours, having produced just 281,000 barrels per day in 2009. But while its output may represent a trickle not a flood in regional terms, this impoverished country relies entirely on the oil and gas sector for its future economic survival. Today, oil production accounts for between 70 and 75 percent of Yemen’s revenue and over 90 percent of its export earnings. The figures are not dissimilar to the likes of Saudi Arabia, for which oil represents 54 percent of overall output.

However unlike the latter, Yemen’s economic circumstances are dire.

It is the most impoverished country on the Arabian Peninsula with an unemployment rate of 35 percent, which is expected to double by 2035.

Around 45 percent of the country’s population is under the age of 15 and the nation is suffering crippling water shortages, with 90 percent of water currently used for agriculture.

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The war on terror While poverty and environmental concerns are the most immediate issues concerning Yemen’s population, terrorism looms as the biggest potential threat to the country’s economic future and to its fragile oil and gas industry. The high profi le terrorist group Al Qaeda in the Arabian Peninsula (AQAP) has strongholds in the eastern Yemeni province of Hadramaut and in the towns of Marib and Shabwa which are home to the oil and gas fields of major international oil companies, including Total and Hunt Oil. Armed tribesmen in the Marib region have blown up pipelines and issued repeated threats to target new gas projects.

The latest reported attempted attack by AQAP was on a pipeline the group threatened to blow up in January this year. Sara Hassan, a security analyst at IHS Global Insight told the Arabianbusiness.com website: “The situation is getting extremely tight where oil and gas installations are and for companies like Total.”

Terrorist threats emanating from the country have become even more high profi le in recent months, following the attempted bombing of a Christmas Day fl ight to Detroit by the Nigerian Islamist Umar Farouk Abdulmutallab. He is believed to have trained with Yemen’s Al Qaeda branch, which has since claimed responsibility for the failed attack. Meanwhile a month earlier, the US launched a missile attack against two suspected Al Qaeda strongholds in Yemen.

According to the business consultancy fi rm Control Risks’ annual security report, terrorism emanating from Yemen is the most significant threat to the Gulf states in 2010. Control Risks analyst, Marie Bos, told Arabianbusiness.com: “Two significant events – the attempted assassination of Saudi Arabia’s Prince Mohammed Bin Nayef and the Detroit airline plot – show increased boldness and innovative new techniques. There have been a number of AQAP arms caches recently discovered in Saudi Arabia and this group is generally accepted to follow up on its threats.”

Oil accounts for 70-75% of Yemen’s revenue

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These security risks could spell disaster for the future of oil production in the country, which relies heavily on the support of private foreign oil companies. Over 20 foreign firms currently operate concessions in Yemen. Without the necessary resources to tap into Yemen’s three billion barrels of oil reserves itself, the government depends on this foreign investment – particularly given the country’s declining output. Analysts believe that the country’s oil supplies could plummet to zero by 2017

“There have been a number of AQAP arms caches recently discovered in Saudi Arabia and it is generally accepted that this group will follow up on its threats” and the cracks are already showing. Yemen’s oil income fell by over half last year, according to Ibrahim Al Nahari, Sub Governor of the central bank’s foreign banking operations. He told the Reuters news agency that the country’s oil income had fallen to US$2 billion in 2009, compared to US$4.4 billion in 2008 – a year-on-year drop of 55.4 percent. He said however that he believed in 2010, oil incomes would recover.

A brighter outlook Despite the gloomy outlook for Yemen’s economy and security situation, Al Nahari, does have some reason for his optimism. Earlier this year, the Yemeni Oil Minister Ameer al-Aidroos, announced that the country intends to boost its daily oil production by ten to 15 percent, bringing the daily total to 300,000 barrels a day. With this aim in mind it has been in negotiations with several international oil companies, including the Chinese Sinopec Corporation, Gazprom and delegations from Chinese, Japanese, Indian, South Korean and Turkish companies. A top priority is to modernise the Aden Refinery which currently produces just 70 to 80 thousand barrels a day. The government aims to boost the refinery’s operational capacity to produce its full potential of around 140,000 barrels a day. The most positive development for Yemen’s flagging oil sector however was the signing of a deal earlier this year with Total which will see the French oil giant invest US$32 million in oil exploration in Yemen. This investment will focus on sector 85 of the Shabwa province and will involve the digging of four wells.

Meanwhile the Austrian oil major OMV is developing the Habban field, which is believed to contain around up to 100 million barrels of crude oil.

As well as focusing on maximising existing oil resources and increasing the barrels produced every day, Yemen is also keen to tap into growing world demand for liquefied natural gas (LNG). It is believed that LNG could play a crucial part in cushioning the Yemeni economy against the blow of falling oil output. Yemen is believed to have an estimated US$17.3 trillion cubic feet of gas reserves and this year it will export an estimated 6.7 million tons of LNG to South Korea, Europe, Mexico and the United States. Total has already invested heavily in Yemen’s LNG future, pumping US$45 billion into the Yemen LNG gas plant. The plant started production last October, with a pipeline linking gas fields in Marib to the Gulf of Aden port of Balhaf. The plant has a capacity to produce up to 6.7 million tonnes per year of LNG and could produce revenue of up to US$50 billion by 2028, boosting economic growth by eight percent this year alone. Total has a 39.6 percent stake in the plant while the US fi rm Hunt Oil holds a 17.2 percent stake.

Equally lucrative could be the recent discovery by the international oil and gas developer Oil Search of high levels of gas at the Al Meashar-1 exploration well in which it holds a 34 percent stake. Previously, last November, the company announced that the Tubb’a 1 well in which it holds a 60 per cent stake had shown capacity to produce up to nine million cubic feet a day during tests.

The continued investment by foreign companies into Yemen’s energy sector bodes well for its economic future, at least in the near term. However, some analysts warn that even the development of a thriving LNG export business from the country won’t be enough to compensate for the gaping hole that will be left once oil supplies dry up.

Samuel Ciszuk, a Middle East energy analyst at IHS Global Insight, said in a report last year: “While LNG exports may offer a brief respite from a future without oil exports, even at full capacity, the country’s potential gas exports will not sufficiently replace declining oil production.” The most immediate threat to the sector however is terrorism and the extent to which it will deter international oil companies from investing in Yemen’s precarious future.

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TECHNOLOGY

MAKING CONNECTIONS As the man behind Shell’s technology strategy CTO Gerald Schotman is one of the most influential figures in the global oil and gas industry. He lets O&G into a few secrets about his role and the latest solutions the oil giant is developing.

Can you sum up what the role of CTO at Shell involves?

Gerald Schotman. As CTO I oversee the way we create and develop technology in Shell, and ensure our newly developed technologies are effectively deployed. We also have a strong external agenda which is open in terms of innovation and representing the company, as well as identifying improved technologies developed by others. Th is fits well with my responsibility for research and development (R&D) for the whole of the Shell group.

How does your role as CTO fit with the team of Shell Chief Scientists?

GS. There is a strong connection. We currently have seven Chief Scientists at Shell, each with a specialist area. They report to the CTO, but an important part of their role is to support and challenge technology development within Shell. As in my role, they also have a strong external perspective, representing Shell and keeping an eye on technology development in the outside world.

You do not have a PhD, which is perhaps unusual in this role. What do you bring to the position?

GS. The choice of not doing a PhD was a deliberate one. I have always been equally intrigued by technology development as by ensuring that technology has impact on day-to-day operations. Following a period in

research I worked in three different operating companies, both in technical and business jobs. So one of the things I bring to the role is the connection between research and how it creates competitive differentia-

“One of the things I bring to the role is the connection between research and how it creates competitive differentiation in practice” tion in practice. I take a genuine interest in all my staff and value their contribution. In Oman a few years ago I worked closely with local staff as a director, helping them to develop their capabilities and slowly bringing out their self-confidence. It was very rewarding.

What is your future vision for Shell?

GS. One of my goals is to make sure Shell is among the top companies for innovation and research. Th is involves not only looking at what we are researching but also how. For instance, one of our programmes

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called enhanced experimentation looks at developing a technology from concept to testing and identifies how to raise efficiency and improve the process. We are also looking at Toyota’s Lean methodologies to cut waste.

The timescale of research in these programmes can be cut by months and even years.

I want to create a sense of developing technology as a business that strives to get the best out of its resources, and that works together as a single community. I also want to build a very dynamic and vibrant community – tapping into new ways of doing things and using all the skills and enthusiasm of our people to bring shape, colour and energy to our team.

Finally, I value the notion of a ‘technology funnel’, into which we pour a vibrant mix of high-potential technology projects from every part of the business and manage them as a portfolio.

But how do you fill the funnel and develop these ideas?

GS. Primarily it is the pull of our businesses, as they represent the customer – and provide our R&D funding. It however also includes an ‘anticipated pull’, as we must think ahead and consider if there is something we could do now that would make a difference to our customers in 10 or 15 years’ time.

“I also want to build a very dynamic and vibrant community – tapping into new ways of doing things and using all the skills and enthusiasm of our people to bring shape, colour and energy to our team” Let me add that although the role of my team is to conduct R&D for Shell, we don’t necessarily have to do it through Shell. There is a huge capacity for innovation outside and we would be very ill-advised to put the blinkers on and ignore this potential source of good ideas. We already have multiple partners in collaborative research projects, from industry to academia. There are many more technologies that can also be taken ‘off-the-shelf’.

The need is to ensure we focus on those technologies that complement Shell’s own and open new opportunities or accelerate existing ones.

Our Gamechanger initiative is another way of feeding the funnel – providing support to people with bright ideas.

We then need to drive the right projects through at a good pace. Our work shouldn’t be completely driven by the urgency of the marketplace – we can’t undermine the quality of the research by taking shortcuts and balance is important – but we don’t have an infi nite timeline.

What do you believe to be the biggest challenge you face in the year ahead?

GS. I think the biggest challenge is making sure that our team is strong with people who are technically creative and have business sense. I want people to be proud to work in our area, both because the work is challenging and stimulating and because we properly recognise people for their contributions. Another key challenge is to build on the good innovation work in the past and at the same time promptly implement our ideas around speed, focus and external orientation. *Gerald Schotman spoke to Kate Bowen and the interview was printed on the www.shell.com website

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ASK THE EXPERT

The digital solution Hamish Strang and Marc Hockfield on the latest digital oilfield technology being pioneered in the Middle East.

Marc Hockfield is ODM3 Account Manager. With degrees in geology and micropalaeontology, Marc has worked with geological software and workflows for eight years. Working for Senergy for the last five years, he has helped guide the ODM3 development, as well as define and instigate data management workflows for some of the largest companies in the hydrocarbon industry.

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dvances in technology over the last decade have led to a new data challenge: integrating, interpreting and presenting the data from these programmes in a unified fashion. Senergy’s Oilfield Data Manager (ODM3) software addresses these issues by amalgamating and displaying all the data to create a digital oilfield. It is being implemented on a range of oilfield development and exploration projects in the North Sea, Middle East and elsewhere in the world. “We’ve carved out an interesting niche,” says Hamish Strang, ODM3 Development Manager. “Before, every discipline was working in their own specialist system and nothing was available to compare data to make the best decisions. But now, ODM3 allows all this data from a field to be stored, interpreted and displayed in a single application – hence the ‘digital-oilfield’ tag.”

ODM3 links directly to several industry-standard geologic databases and softwares – such as Openworks, OpenSpirit, Petrel and Geolog – to integrate data. Once connected, ODM3 can also load data from dozens of other disciplines such as biostratigraphy, chemical stratigraphy, pressure data and such.

On loading well data, ODM3 can display seismic grids and GIS (Geographic Information System) files to give a client an idea of their data spatially. Strang explains: “The base map display allows users to access all their data directly from the map, as well as create cross-sections and montages. Bubble maps to show well properties can easily be created. Users can also display GIS and satellite images, giving a clearer spatial understanding of a region by having map data visible and well data instantly accessible.”

Mapping out data Recently, the ODM3 team has been working on integrating field-history data and presenting it on maps – including production data, injection rates,

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Hamish Strang is Product Manager, ODM3. He has over 25 years of experience in the IT and oil industry including experience in software systems for MWD through to managing large exploration data sets. Since then, he has worked on product development for biostratigraphic database systems and development of the ODM3 software package.

pore pressures and more; this link can be customised for virtually any database or spreadsheet. The output maps show geology, GIS and time-stamped data clearly and with the full dataset immediately accessible. This brings tremendous benefits to clients in that they have access to cross-discipline data to help understand the performance of their field and because it is all done in an active database, the display can be edited, investigated and customised quickly. The results have been spectacular. One multinational client has seen their well review preparation times cut by more than 80 percent – resulting in more frequent reviews, better understanding of field history and dynamics and, ultimately, increased efficiency and time savings. Meanwhile, an asset group used the field-history integration in ODM3 to discover links between fields, which were previously thought to be unconnected.

In addition to enhancing workflows in developed fields, ODM3 works extremely well with exploration data. ODM3 has been utilised in a digital oilfield concept and as a well database to store and work with well-related data. The ability to spatially display and manipulate well data in sections and map environments has provided the missing link between downhole and areal information. Interpretation and visualisation tools mean that data can be explored and edited quickly and interactively; montages with maps, text and images are built up in a PowerPoint-style tool while interpretation is being done, allowing presentation-quality output while still having instant access to geological data.

These montages can then be cut and pasted directly into other Windows programmes, eliminating large drafting jobs. Synergy Account Manager Marc Hockfield comments: “We find that the Middle East region uses ODM3 in extremely diverse ways. With the new exploration projects in the region combined with continued exploitation of brownfield sites, there are massive amounts of data out there that are now being understood better through ODM3.” n

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EXPLORATION

In an exclusive interview, IDC’s Catherine Madden reveals the three vital factors in developing the next generation digital oil field.

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igital oil field technology entered the industry in the early 1960s, originally to help assist with exploration activities, particularly in the form of digital seismic technology. It wasn’t until the next couple of decades that the term ‘digital oil field’ gained prominence and began to include the use of soft ware, hardware, instrumentation, communications, business and engineering process improvements in EMP activities. Even then, it wasn’t until the mid 1990s that the term was used by the super majors who were working on cultivating strategies to further integrate technology into the business. Nonetheless, the advent of digital oil fields has had a significant impact on the way industry approaches the business of oil exploration and production. “It’s changed exploration in that it’s often allowed companies to leverage new or emerging technologies,” explains Catherine Madden, Research Analyst for IDC’s Energy Insights. “When I think of the digital oil field I’m thinking of technology that will help me achieve the ultimate goal – which I think is the same for all oil companies no matter how large or small – of the economically feasible recovery of hydrocarbons.”

While the digital oil field has essentially been around for 50 years, it is only now that the fundamental objectives of the concept – enhancing reservoir recoverability and optimising production – have evolved to a point that people are looking at the digital oil field as a way to run all operations from exploration to the refinery, incorporating standardisation and process integration. “Digital oil field efforts have essentially resulted in a positive impact on reservoir recoverability, production rates and total cost of ownership and those numbers probably vary from company to company depending on their strategy and the level of investment they have made,” explains Madden. “Energy Insights has done case study work as well as reports that have concluded that reductions of cost and improvements in productivity are possible, and many large oil companies such as Shell and Chevron have reported the same in relation to implementing a digital oil field strategy.”

But while many of the largest oil companies in the world have a programme in place to support the digital oil field, many are still looking at how to accelerate it. Madden believes that the top priority remains the same – namely, hydrocarbon extraction. However, she highlights that a critical link in the digital oil field remains the human element. “Initially there was much attention placed on technology as the means for companies to solve their problems, optimise the exploration and production processes and improve the ROI,” says Madden. “There wasn’t much attention paid to the role of people and processes in achieving those objectives. But now I think the top objective is to sustainably support the development of a holistic digital oil field strategy – and that includes not only technology as a tool to aid that process, but also the teams of people that do the work, as well as the different business processes that are associated with exploration and production.”

In essence, companies that wish to accelerate their digital oil field will be required to understand the equation that permits the right balance between technology, people and processes. Looking at the digital oil field in 2010, Madden insists these three objectives need to be lined up together as opposed to implementing technology alone, and goes on to explain that the importance of this equation is slowly being recognised and that she sees improvement in many areas, including the degree of human involvement in oil field process of exploration and production. “Some

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of the changes we’re seeing include looking at workflows and what can be automated. We’re talking about the integration of technology across distinct areas – so integrating more processes between exploration and production, for example. I think we’re currently talking about things like project management portfolios when essentially we should be looking at the entire value chain and allowing for as much integration and as much collaboration across that value chain as possible. And when I talk about the value chain, I’m really talking about everything from the moment exploration begins, through the process of drilling until the point you finally recover it and deliver it to its refinery source.”

The power of three Madden goes on to explain that each of the three main factors – people, processes and technology – will play a major role in the next generation digital oil field. Indeed, as each facet of these factors improves, so too will the digital oil field itself. On the technology side for example, Madden expects to see an increased use of sensors, as well as a continued improvement in high performance computing. “I also think remote visualisation and service orientated architecture are going to continue to grow within virtualisation; communications that allow collaboration and even communications around security will be important too,” she says. “Technology that aids collaboration is going to continue, and while it’s already playing an important role, it’s going to become critical that you can share information – not just using email, but maybe working in a virtual room together or using virtual technology to look at the same document together and make changes to it, or using a virtual whiteboard to point out certain things you want changed.”

In terms of the people factor, Madden believes a significant improvement is needed in addressing the top two challenges facing the industry – the ageing workforce and the need to work with geographically dispersed teams. The ageing workforce will play a critical role in the number of available employees in the oil and gas industry over the next few years, and while the number may be mitigated to a certain point by the global financial crisis, the number of skilled workers available is set to shrink. In addition to a shortage of skilled workers, the increasing number of global projects impacts how these projects will be managed.

Finally, in regards to processes, Madden sees one fundamental factor to the digital oil field strategy that must be addressed: aligning the business and technology strategy as well as implementing automated workflows, improving business practices and re-engineering existing processes in order to address the workflow. “There may be great new technology out there, but IT alone can’t be the driver for the implementation of the digital oil field strategy, and neither can the business; the two have to be working together,” she asserts. “The business has a need to improve production and there’s technology out there that can aid that.”

There is no doubt that some of the super major oil companies like ExxonMobil, Chevron and BP are working towards this right now. Many of these companies have either reorganised their company or realigned

their goals regarding their digital oil field strategy to include business as well as IT and improve the communication between the two groups.

Indeed, companies like Chevron, for example, have invested a huge amount in emerging technologies in the oil and gas industry. The largest oil companies are certainly looking at the next generation digital oil field and accelerating it from how it was perceived in the mid-1990s.

“While it is not fully mature yet, there is a significant amount of investment happening. We’ve gone through the first wave of the digital oil field and learnt from that first level of implementation that it’s not all about technology; now we’re looking to ensure people and processes are aligned with the technology, using best practices, looking at getting a return on investment and improving production rates,” says Madden.

“Energy Insights’ primary research indicated that in 2008, even national oil companies were looking beyond just investing in back office IT such as ERP systems; they too are looking at setting aside investment dollars for the digital oil field. And while it may not be on the same scale as some of the largest oil and gas companies, it is a priority for smaller companies too.”

“There may be great new technology out there, but IT alone can’t be the driver for the implementation of the digital oil field strategy”

Information overload

However, while investment is being poured into the digital oil field, one criticism is the exponential explosion of data it generates. Implementing a tremendous amount of technology is bound to result in a wealth of information being collected, ranging from sensors that reveal how well the field is performing to different information about the reservoir. Such data floods in 24 hours a day and puts a great strain on the IT infratsructure. Madden believes this is certainly one aspect that companies are attempting to address.

“Companies are looking at their approach towards structured and unstructured data in order to understand how best to use this information and ensure that employees don’t have to spend days wading through information as opposed to actually using it. You have to address things like how to handle structured and unstructured data, using business intelligence and dashboards to indicate the performance.”

Madden cites the greatest risk associated with the recent global recession as the likelihood that oil and gas companies will delay capital expenditure exploration budgets due to tight fi nancials. “This is the area that has made the industry the most nervous,” she confi rms. But while businesses are focused on the short-term boost to the budget sheet, the long-term risk is that by not making an investment to explore for new sources of oil, companies will be left at a significant disadvantage four or five years (or even further) down the line. And with economically accessible reserves getting increasingly hard to find, companies are required to look for reserves further offshore and deeper in the ocean.

So while Madden believes that the next generation digital oil field is in the pipeline, it is clear that the investment in people and processes – alongside the technology – must not be neglected at this crucial stage of its development.

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EXECUTIVE INTERVIEW

Harnessing the power of Parker Despite dramatic advances in computation speed, the petroleum industry continues to demand quicker ways of finding oil. Geosoft’s Gerry Connard explains the advantages of using Fast Fourier Transforms (FFT) for gravity and magnetic modelling.

What research is your application based on?

Gerry Connard. Robert Parker’s seminal paper published in 1972, The Rapid Calculation of Potential Anomalies, has led to a revolution in using FFT for gravity and magnetic modeling using ‘gridded’ data. Since then, a number of additional papers, including some by Parker himself, have extended and improved Parker’s original work. Richard Blakely’s 1995 book summarises most of this development and provides some additional, related FFT algorithms for FFTbased gravity and magnetic calculations (such as Blakely’s ‘Earth Filters’).

What are the advantages of the FFT-based methods?

GC. Parker describes in the introduction of his 1972 paper that the computation time for a model grid containing N points is proportional to N ln(N). For equivalent space-domain calculations on the same type of model, the computation time is proportional to N2. This difference is not so significant for small models. For example, to calculate the response of a grid with 100 points, the space-domain approach would require approximately 20 times as many calculations as the FFT approach. However, as the number of grid point increase, the ratio of the number of calculations in the space-domain approach compared to the number of calculations in the FFT-based approach increases rapidly. For a grid with 1000 points, the ratio is 144. For a grid with one million points, the ratio is 72,382. So if the FFTbased approach took one minute of compute time, the space-domain approach would take 50 days.

Are there disadvantages of the Parker method?

GC. There are pitfalls in the FFT-based calculation approach, including but not limited to the problems of edge effects, periodicity and the fact that the original Parker algorithm is based on the convergence of a Taylor-series approximation. With two decades of practical experience using the FFT-based approach, most of these problems have been solved or at least minimised.

For example the ‘Earth Filter’ algorithm does not need the Taylor-series approximation.

What are your future predictions?

GC. The FFT approach continues to evolve. Two papers by Parker in 1995 and 1996 extend his method to compute the results on an uneven surface. This al-

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lows more flexible models that more closely resemble a real earth model which are more appropriate in many exploration scenarios. In 2009, a new paper published by Caratori Tontini and others describes how to use 3D FFTs for gravity and magnetic calculations that will likely lead to significant improvements in FFT-based methods.

Although raw computing power continues to grow according to Moore’s Law, our computing needs are growing even faster. Explorers today are taking advantage of a wealth of detailed exploration data to build larger and more complex models with grid sizes often exceeding one million points. FFT-based methods will play an important role in tools for the utilisation of gravity and magnetic data in large, detailed models.

In spite of the disadvantages of the computational speed of space-domain techniques, they will also continue to be important tools in the interpretation tool kit. Space-domain techniques

“With two decades of practical experience using the FFT-based approach, most of these problems have been solved or at least minimised” are inherently more flexible than FFT-based techniques and more easily utilised for inversion schemes. One powerful approach is to use a hybrid technique that combines both FFT-based and space-domain techniques in a modeling tool. Cloud computing (such as using large banks of parallel processors at a remote site) is also likely to be part of our exploration computing future.

This approach is already being used by companies like Microsoft and Google to bring amazing computing power to desktops around the world. n

Gerry Connard is the Petroleum Industry Market Manager with Geosoft Inc., a Canadabased exploration software company. Connard is a geophysicist with over 30 years’ experience in the exploration industry. He founded NGA, Inc. and developed gravity and magnetic profiling and modelling software – GM-SYS Profile and GM-SYS 3D.

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COMMUNICATION FOCUS

Improving oil and gas collaboration According to a new report, oil and gas pros view social media as important for productivity and collaboration; however, few firms have the tools in place to capitalise on it. sources necessary for their jobs. With an estimated 65,000 engineering professionals in the global oil and gas industry today, this translates into a potential loss of almost 10 million people-hours a year among engineers alone – an average net annual loss of US$485 million for the industry, calculated according to US Department of Labor salary statistics.

“During this time of economic upheaval, when every dollar counts and effective decision-making is crucial, new technologies such as social media tools can help oil and gas industry professionals to find information, collaborate and generally be more productive,” says Craig Hodges, US Energy and Chemicals Industry Solutions Director at Microsoft. “In an environment with fewer workers and less resources, this is incremental productivity our industry can use in finding new reserves, improving execution of capital projects, driving new innovations and reducing costs.”

More effective collaboration tools

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esearch has revealed that the oil and gas industry loses almost half a billion dollars annually due to inefficiencies around finding, using and sharing information among engineers alone. Around 40 percent of oil and gas professionals believe company adoption of new social media tools, including social networking sites, would boost productivity on the job, yet only one in four report leveraging these newer tools to capture and share important information internally, according to a new Microsoft and Accenture survey released at the Microsoft Global Energy Forum 2009.

The Oil and Gas Collaboration Survey 2009, conducted by PennEnergy in partnership with the Oil & Gas Journal Research Center, surveyed industry engineers, geoscientists and business managers worldwide and found that more than 70 percent believe that collaboration and knowledge-sharing are important for driving revenue, cutting costs and contributed to the health and safety of workers. However, in spite of this, most respondents stated that their organisations are still using older means of collaboration, such as face-to-face meetings, emails and conference calls – even though newer, more sophisticated technology tools are available and in demand today.

Perhaps more telling is that 61 percent of respondents said they spend at least one hour each working day searching for information and knowledge

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The survey pointed to one path companies can take to help maximise productivity and facilitate knowledge-sharing and capture: specifically, 41.5 percent of those polled said they could save at least an hour every day by using these newer and more effective collaboration tools.

Surveyed professionals also revealed that advanced collaboration and information-sharing capabilities bring value not only in sharing enterprise knowledge but also in completing operational projects. For example, 74 percent said that these capabilities are very important in managing capital projects to drive down costs; 51 percent said they are very important in sourcing scarce technical skills needed to enhance revenues; and 50 percent saw these new technologies as very important to the sharing of health and safety advisories or experiences.

“Companies are dealing with several trends right now, not only the ageing workforce walking out the door with decades of knowledge, but also experienced hires coming into their businesses who need to understand a new corporate culture,” says Claire Markwardt, Senior Executive at Accenture’s energy practice. “Companies have an opportunity to supplement their existing collaboration capabilities with newer tools such as podcasts and social networks to accelerate the sharing of knowledge, increase teaming and augment communication between their workforces in different regions.”

While more than half the respondents favoured adopting social media technologies to help shrink the productivity gap, only 37 percent of respondents think their companies are prepared to facilitate enhanced sharing and capturing of the company’s intellectual capital. When asked why, almost half (48 percent) said company management doesn’t view these issues as a problem. And 44 percent laid responsibility for lack of readiness on older workers

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The power of IT Long-term business success needs to be built on two things: innovation and productivity. New desktop and server solutions allow employees easy access to information anywhere at any time, while organisations can reduce risks through improved security and drive cost savings through virtualisation and streamlined management capabilities.

In 2000, subsea services and construction support firm DeepOcean was among the first in its industry to implement the Windows platform for its onshore operations and offshore data processing. DeepOcean is now migrating to Windows 7 and Windows Server 2008 R2 because of its need to support its sales force and engineers who travel between onshore and offshore locations. These mobile employees rely on portable computers that make up more than 25 percent of the company’s computer fleet.

When DeepOcean migrated to the Windows platform, it implemented the Windows NT 4.0 operating system on its 50 client computers and the Windows NT Server 4.0 operating system on its 10 servers, which it is gradually upgrading from Windows Server 2003 to Windows Server 2008 R2. In an effort to enhance security for its portable computers and to address challenges with its virtual private network solution, the company also decided to migrate to the Windows 7 operating system. As a result of the upgrade, DeepOcean has simplified IT management, enhanced IT security and improved employee productivity.

“Windows 7 has enabled our mobile workforce to connect to the corporate network and access all the resources they need faster and more easily,” said Per Arne Strømø, IT manager at DeepOcean. “At the same time, the technology offers us a highly secure and reliable tool to help protect our confidential data and intellectual property even when on the road.”

who do not typically use digital knowledge-sharing capabilities. Still others said that vital company information is locked on individual PCs or spreadsheets not available for easy sharing.

“In the oil and gas industry, collaboration is a key strategy to reduce costs, improve efficiencies and promote collaborative working relationships among oilfield asset teams located in remote locations around the globe,” says Jill Feblowitz, Practice Director at Energy Insights. “Energy Insights believes that the momentum behind Web 2.0 will bring it to the oil and gas industry.

Web 2.0 technologies can support the following industry requirements: connection with remote geographic locations, knowledge capture, knowledge access, informal knowledge sharing, and joint ventures and team projects.”

Capturing knowledge still challenging Survey respondents also confirmed that concern about capturing knowledge from experienced workers before they retire or leave the company is prevalent. As might be expected, more than half (53 percent) reported that ageing workers are retiring in increasing numbers.

However, survey respondents stated that the tools primarily used to retain this knowledge and intellectual capital from retiring workers are largely

older methods, such as electronic file shares (64 percent), databases or repositories (58 percent) and written documents/physical files (58 percent). In fact, almost a quarter of respondents reported exit interviews as the tool used most often to capture knowledge from these workers.

Respondents overwhelmingly said new collaboration technologies can help stem this flow of exiting knowledge. Yet when asked how well their corporate cultures support the adoption of these new tools, only about one-third of respondents think their company cultures are well aligned with implementation of new social media technologies. Far more view their organisations as not proactive, not encouraging and/or opposed to the use of these information technology innovations as business tools.

Technology in action Like countless other industry players, ConocoPhillips has three generations of employees working together side-by-side or dispersed around the world, and a significant number of the experienced workers are preparing to retire soon. That, plus regular attrition, creates the need for effective knowledge sharing.

“With our intranet-based discussion forums, state-of-the-art browseand-search tools, and content management processes, our portal structure goes a long way towards addressing the looming generational gap and maintaining our intellectual capital. This is a key part of our strategy to retain critical knowledge,” says Dan Ranta, Director of Upstream Knowledge Sharing at ConocoPhillips.

Due to the global nature of the oil and gas industry, workers must additionally work with internal and external contacts that are located halfway around the world and may never meet face-to-face. “Portal sites make it possible for a diverse, global workforce to connect with each other easily, aided by a business-focused network structure that encourages people to form trusted relationships regardless of their location,” he adds.

Take the example of how an employee in Indonesia posted a question to the network’s online portal enquiring about whether it was safe to extend the run time of a power turbine beyond its scheduled maintenance overhaul. The timing of the overhaul would have resulted in a significant impact to production while the turbine, and the gas compressor it drove, were temporarily shut down. Expert engineers in Alaska, Australia and the corporate engineering group all responded, indicating it was both safe and permissible to continue running the equipment as long as the power it produced was acceptable and vibration levels were below alarm limits. By temporarily extending the turbine’s run time and deferring the overhaul to a more opportune time, the Indonesian unit avoided millions of dollars in additional lost production without compromising safety.

As the oil and gas industry becomes increasingly savvy in its use of information portals, new communities of internal and external users will emerge that share insight into resolving difficult industry challenges – from health, safety and environmental concerns to avoiding revenue loss. “The business impact of collaboration has made ConocoPhillips’ people and operations safer, lessened environmental impacts and helped our operations reduce or avoid lost production,” says Ranta. “Our operations have become more efficient, as in the case of our North Sea Business Unit that created and implemented a new production optimisation centre. Along with reducing production losses, the POC has improved production coordination, planning and communication.” n

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ASK THE EXPERT

Agile petrophysical analysis Time is money in the oil and gas business. Graeme Eastwood discusses the secret to agile petrophysical analysis and the drivers behind it.

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nformed decisions in exploration and production begin with a good understanding of the subsurface.

Placing the next well, how to maximise production or the best approach to secondary recovery – such decisions improve when supported by petrophysical evaluation. Time is a rare luxury in these decisions and, regardless of complexity, the analysis must be completed rapidly to be useful. Agility describes the combination of balance, co-ordination, speed and reflexes that enables quick completion of a task and timely course corrections along the way. These agile characteristics apply well to petrophysical analysis, enabling quick evaluations that adapt to each situation.

elastic model in a multi-user environment.

The analysis becomes a co-ordinated effort that both speeds the analysis and improves the results by allowing real-time assessments, experimentation, idea sharing and joint decision-making. High quality logplots, crossplots, maps and other presentation tools also support collaboration and fast, informed decision-making. These tools make it easy to share results, and coordinate next steps, whether during peer review or management presentation.

Fast, iterative modeling Petrophysical analysis is not a one-time task that proceeds in only one direction to an end result. It is a multi-directional process that encompasses multiple disciplines and re-

continually improve and modify their methods for best results in each analysis. What works well in West Texas may not work well in the Middle East. Adaptive petrophysical tools must rapidly add new capabilities as they are needed and allow geoscientists to work with data suitable to each situation.

In PowerLog, for example, two new modules added through agile development can now be used to analyse laminated sandshale and other bedding sequences, providing interactive overlay graphs for analysis. Once these inputs are used to correct resistivity for anisotropy then saturation of the sand beds is computed and thin, laminated pay can be seen more clearly. The other module lets users easily and interactively pick, save, recall, edit and share dips from borehole image logs.

Integrated petrophysics The cornerstone of agile petrophysical analysis is the ability to perform rock physics modeling within a petrophysical framework.

Th is integration provides balance and can discover, and correct, such issues as borehole and invasion effects, unknown mineral mix and properties, thin and laminated beds, missing logs or gaps, and 4D time-lapse effects. When petrophysics and rock physics are combined in an integrated workflow they can be performed in a tightly integrated loop improving the consistency, veracity and utility of the results.

Th is enables rapid shift ing between petrophysics and rock physics and holds parameters, zones and equations constant between the two disciplines. Integration reduces uncertainty in corrections and increases efficiency. Improved accuracy and data trustworthiness make precise reservoir management viable.

Collaborative analysis For the best results, agile petrophyscial analysis should be collaborative in all phases.

Multiple petrophysicists and geoscientists should be able to work together on the petro-

“When petrophysics and rock physics are combined in an integrated workflow they can be performed in a tightly integrated loop improving the consistency, veracity and utility of the results” quires iteration as more information becomes available or new reservoir properties emerge.

The petroelastic model must also incorporate additional field data as new wells are drilled.

Details from these wells could challenge the fundamental model and must be incorporated at that level. This process may involve hundreds of wells and many geoscientists who must conclude the analysis quickly to be effective in decision-making. The best models are those that bring in new data and incorporate it rapidly without prejudice.

Adaptation to new demands Quick reflexes are as necessary in the oil business as they are in nature. Geoscientists

Agile petrophysical analysis provides significant benefit to geoscientists and the decisions they support. It is a process designed for speed but able to make quick adjustments as needed, provide cross-discipline balance and co-ordinate for best decision-making. In these times of increasing geologic complexity, challenging plays and economic pressure, agile petrophysical analysis is just what the industry needs.

Graeme Eastwood is Middle East Regional Manager for Fugro-Jason, a leading provider of reservoir characterisation products and services. He joined the company in 2003 as Business Manager for Southeast Asia and moved to the Middle East in 2007. Eastwood has 17 years’ experience in the industry, including previous positions within Schlumberger.

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SAFETY FOCUS

In safe hands The oil and gas industry faces mounting challenges when it comes to preventing accidents and injuries, as well as understanding the impact of operations on the environment. We catch up with Yassin Darwish, Dana gas Egypt HSE Manager, to get his take on standards.

The oil and gas industry is perceived by some young people as a dangerous career choice. How have health and safety efforts and standards improved in recent years?

Yassin Darwish. In recent years we have set up a committee for the oil and gas operating companies in Egypt. We are trying hard to solve all the problems as well as improve the standards. Our main concern nowadays is with our local contractors in Egypt because they are not meeting any of the international standards. So we are working hard on this issue with cooperation, of course, from the government to have

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new legislation. Th rough these many committees and with the government and five NGO’s running right now we are working on those issues. We feel we are improving and trying to make it safer for the corporations and also preserve the natural resources as much as we can. We have training for all issues relating to HSE in the oil and gas industry to raise standards for the workforce.

And what would you say are the main risks that oil and gas workers face today?

YD. We have huge challenges in Egypt with our local workforce and also in the community because literacy in Egypt is not high. The ignorance to the safety, health and governmental issues is very high, while education on health and safety issues is not very effective. We can say that our workforce falls into two categories: they follow the rules while they are on the sites but when they go outside our worksites they are exposed to the community that is not following the rules. One of the many challenges in Egypt in general is road safety, and according to the WHO we have one of the highest fatality rates in the world.

What’s the best approach to tackling HSE issues and complying with legislation?

YD. Most of the oil and gas companies are following very fi rm procedures, but compared to the whole global community we are not so effective. However, the Egyptian government is very cooperative on these issues and in trying to reduce incidents as much as possible.

Also, in the tender process they look for HSE statistics and the history of the company. An IOC will normally have high HSE statistics but if they have environmental fi nes in other countries, for instance, they will face restrictions. So we are working on these issues.

It is well documented that the oil and gas industry faces skills shortages, with experienced personnel approaching retirement and graduates tending to pursue other careers. How is this affecting HSE efforts?

YD. In HSE in Egypt it is not easy to fi nd high calibre and well-educated staff that have the right experience. However, this is not just a problem for Egypt – it is a worldwide concern. We try to improve this situation through education. We now have some UK certificates and also American certificates we are trying to introduce in Egypt.

Most of the workforce now gets education and we also try to help new generations so that old HSE managers are passing on their experience to tomorrow’s managers.

The MENA region can be a fairly inhospitable region with hot and dusty conditions to contend with, not to mention security and political concerns. How does this affect work?

YD. If you take the IOC, they are working to their standard set of rules. Then comes the difficulty of understanding and implementing this in different cultures. As I said earlier, there is ignorance in some countries – not just Africa but worldwide. If you are educated in HSE from your first year with an oil and gas company you never achieve what an IOC wants, especially if you work in many countries.

Of course, there is a standardised approach when it comes to the envi-

ronment because there are conventions that we have to adhere to. But how we implement those conventions and how we understand them, is a challenge. I believe the NGOs have a much stronger understanding of this. They have a lot of enforcers so are more effective than governments on these issues.

How does the approach of the IOCs differ to that of NOCs? YD. Standards are created by the companies and most of them want to work to the minimum standards in order to prevent incidents. There are a lot of IOCs who are trying to continually improve the standards and, at the same time, carry out sustainability or corporate social responsibility (CSR). So some companies are taking responsibility to try and improve awareness and understanding of the impact on the local communities. On the other hand, other companies with diff erent standards may be doing physical things like refurbishing a community facility. Th is means there is a large variance between the standards of the oil companies.

“An IOC will normally have high HSE statistics but if they have environmental fines in other countries, for instance, they will face restrictions. So we are working on these issues”

Do you foresee any major changes in Egypt with HSE over the next few years and how will this impact on your operations?

YD. I think Egypt is moving ahead right now in its effort to improve standards. You can see improvement because we are trying to communicate and interact more as IOCs when it comes to HSE. With these strong relationships we are approaching governments and NGOs because they are very willing to help. I believe that in fi ve years from now we will be very effective in this as an industry. They, like us, are trying to protect the environment and our natural resources.

Has the global economic downturn affected HSE standards within the industry as a whole?

YD. I don’t want to name companies, however most operate to the same international standards and if they violate these standards they may be fi ned. So they need to make sure they do the right thing. What we are trying to also do now in Egypt is standardise IOC standards according to the best that are out there. We are also negotiating so that we have government, not IOC, standards and this is enforced as the minimum HSE requirements. In Egypt it is not fi rm at the moment but we want to make it clear and not from the interpretation of any company. Th is will improve HSE standards in Egypt a lot.

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INDUSTRY INSIGHT

A reliable safety net Just complying with standards doesn’t go far enough, says Jaakko Uotila.

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recent fi nding in Trelleborg, Sweden, paints a gloomy picture of how safe is safe.

A routine check revealed that several Swedish passenger ferries carried life buoys that did not float. Instead, they soaked up water and sunk.

Surprisingly, the defective life buoys had been approved as meeting the European safety standards, arguably not among the weakest in the world. Looking at this striking shortcoming as a manufacturer of safety equipment, there is only one conclusion to be made: fulfi lling standards is not enough. Instead, we should always look at real-life safety needs.

In offshore structures, safety is always an issue.

Whether it’s about running the daily routines, planning maintenance operations, or organising transport, there are risks that need to be minimised. Safety standards already govern the majority of offshore safety equipment.

For the perimeter safety nets used on helidecks, there are a great variety of standards in different markets, from professional regulations to virtually non-existent recommendations. Even today, many territories accept perimeter nets that are tested by dropping sand bags into the nets.

The belief is that this concludes whether the net holds or not. Unfortunately, drop tests will not reveal whether the net holds a weight any heavier than the bag, or even the same bag again. It’s hard to imagine anyone volunteering to do a test-jump into the corroded or ragged perimeter nets, even if they have just been drop tested.

Resisting abrasion Safety of helideck perimeter nets is determined by design, material and installation method. In offshore conditions, the nets need to survive a combination of sun, rain, ice, salt water and guano. Safety nettings of poor design or made of poor materials may well comply with regulations at fi rst, but can fall below their specifications surprisingly quickly. Due to inadequate testing while in use, deterioration often goes unnoticed. Frequent renewal of safety nettings is arguably the best way to uphold safety. However, offshore installation projects tend to be difficult and expensive. As the cost of installation often exceeds the cost of equipment, there can be a temptation to wait for another year, maybe two. Based on more than a decade of research and development of helideck safety nets, we have proven that the typical lifespan of just one to two years can be extended to up

to nine to 10 years by using high quality materials and careful design.

Improved testing is a must In order to assure offshore personnel that their work environment has been made as safe as possible, regardless of where in the world they operate, more stringent and more widely adopted standards are strongly called for. I am delighted to note that there are ongoing efforts to improve standards and harmonise the requirements across territories. The pioneering work done by the North Sea authorities will hopefully lead to similar actions in other regions.

In safety nettings, the key to long-term safety is balanced structure and strength. Nettings should keep their form and structure, and the installation method should ensure correct operation. A crucial part of upholding the safety of helideck nettings is to regularly test the materials for remaining strength. A testing method used in North Sea for some years already is to include extra straps in the nettings. Test straps can be then detached at regular intervals and sent to labs. Results tell the exact current strength of the material, and comparing them with long-term field testing data and textile engineering theory enables the estimation of the net’s remaining lifetime. There is talk about safety products that can simply be installed and forgotten. In my opinion, saying something like that is outright irresponsible.

“Whether it’s about running the daily routines, planning maintenance operations, or organising transport, there are risks that need to be minimised”

Jaakko Uotila is the Managing Director of Frictape Net Ltd, the producer of ultra-safe Frictape landing and perimeter nettings designed for offshore helidecks. Frictape Nets feature a completely balanced structure and hold DNV-type approval certificates. Frictape Net customers include BP, Conoco Phillips, ExxonMobil, Shell and Statoil Hydro.

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HSE

The International Association of Oil and Gas Producers has been publish hing saffety data since 19 985. Hans Jorn Johansen, Head of the Safety Committee, exam min nes the im mpro ovem men nts the industry has seen in the past 24 years and lo ooks at what can be done in the coming years to enhance current industry standards.

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n the last 20 years or so the oil and gas industry has acknowledged that accidents are preventable, that safety is a value and that it is not a competitive edge. It is important to emphasise that accidents are not unmanageable, they are simply something of the past. I was attending a conference in Tehran just a month ago and it was particularly impressive to hear in the opening ceremony that accidents are preventable, that we do not need to have accidents happen.

Lift ing and hoisting, driving safety and diving safety are our absolute number one killers and we now see statistics that these three areas are the ones that we still do not have a good handle on and continue to see too many fatalities occurring. These are the accidents where we see a high frequency, meaning they occur frequently. They may only kill one or two at a time but they are just as important as the accidents that occur less frequently but incur a high number of fatalities. We have therefore targeted our work in the last five years towards these three particular areas. A few years ago, a set of best practices was issued in regards to lifting and hoisting to address recommendations from the best operators in the world and we are hoping that everybody will be using or implementing these best practices. The documents are freely available to anybody and we promote them at all the safety conferences we can around the world. Last summer we published another recommended practice on diving safety also because this was the third area we have been targeting in the last five years.

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Low frequency, or the accidents that happen very rarely – say every one to three years – have something to do with what we call process safety. The purpose being that you maintain your plant such that you know you can rely upon safety features and that it will not all of a sudden break down or cause a series of events that eventually cause the whole thing to blow up, killing or injuring a lot of people. While we are less likely to see these accidents it is nevertheless an important area to deal with because the accident may have had a long time to build up, slowly breaking down the very complicated system that has been set up to ensure the safety and integrity of the plant. These accidents are much more complicated to deal with than a straight-forward accident that just kills one person at a time.

Best practices

With so much experience in the oil and gas industry available today it should be possible to take down and state the way you do business and then reapply that in a different part of the world in a different plant, and in a sense provide comprehensive safety guidelines, or best practices, for all workers. However, for some reason it doesn’t seem to be as simple as that. In my mind if you do not try to accumulate your experiences and learning’s and transfer them to other parts of the company then you are wasting your energy.

And that is one of the good things about being active in OGP, you are no longer competing with best practices, you are sharing your best practices and opening up completely to anybody who wants to know something; you can get this information through Pressure a couple of mouse clicks on the computer or by callOil and gas companies are engaged in exploration ing somebody, to help you immediately. I believe that is projects in some of the most inhospitable regions of the world truly inspiring. requiring high standards of safety. While In order to achieve this, we at the best practices are developed and can be OGP will need to better manage our taken and implemented around the world documents and we need to have a more A global industry there are many more challenges when interactive webpage that people can starting from scratch in the middle of really use, because sometimes it is not The International Association of Oil and Gas nowhere as opposed to being in a fairly enough to have the telephone numbers Producers (OGP) encompasses most of the developed region of the world where of the right people to call. Sometimes world’s leading publicly-traded, private and facilities are available. The International you are not ready to call somebody and state-owned oil and gas companies, industry Association of Oil and Gas Producers say, ‘Look here, I need help, I’m standassociations and major upstream service (OGP) represent around 50 percent of ing in the middle of Alaska’. Sometimes companies. OGP members produce more than the world’s oil and gas productions and people want to go to a webpage and half the world’s oil and about one third of its gas. from our perspective best practices are look at a Q&A, and so that is what we’re OGP has been publishing safety data since 1985. increasingly being developed and taken developing at OGP right now. We have Though there have been improvements in terms around the world. That means our memset ourselves a target to be the foremost of fatalities in recent years, much remains to be bers represent a large proportion of the oil reference point as regards to health and done, particularly in the areas of land and air and gas exploration and production that safety in the world and we are going to transportation, marine transfer and lifting and takes place. Of course I can only speak on build databases of all this information hoisting, as well as diving and marine operations. behalf of the 50 percent of the world’s oil that anybody can access from anywhere In particular, OGP’s Safety Committee aims to: production that our members represent in the world. so we still have challenges as regard to In addition we will be developing key • Promote the integration of safety into the the other half of the oil production that performance indicators because we need everyday business of OGP member companies takes place through other companies that to have these in place before we can start and other E&P companies and contractors we are not directly dealing with. saying these are the best practices. We • Provide safety leadership with cost effectiveness Will we come to represent more than will be starting to collect information to • Promote a level playing field for safety that is 50 percent of the world’s oil production? know what to manage and this will be the recognised by the E&P industry and administered Well, only time will tell, but over the last starting point for safety integrity works, by national and global regulatory authorities. two years we have been quite active in but before this we need the indicators. promoting OGP as an organisation that We will start publishing them from next gives something to its members and I have year onwards and this will ultimately seen interest from companies in parts of result in a best practice document. We the world were we haven’t been so strongly represented, such as Australia are defi nitely spreading the safety message around the world and are also and the Far East. We have actually seen seven new members just recently, hoping to gather more information on performance indicators and on including a company in Greenland, and I have seen the growing interest experiences, but we need more information before we can publish a best of being part of a good organisation. practices document on this because it is such a complicated subject.

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ENGINEERING

Engineering solutions As team leader in the operation engineering department of Dubai Petroleum Yusuf Al-Taher is on the frontline when it comes to solving the technical problems the company faces and coming up with innovative solutions. He sits down with O&G for a quick chat about his role.

As operation engineering team leader what different aspects of the company are you involved in?

Yusuf Al-Taher. I’m involved in the day-to-day support of off shore operations, the oil and gas operations and I give the support required to maintain our production.

What are the main challenges that you are dealing with currently within your role?

YAT. The main challenge now is to effectively optimise oil and gas operations to keep on target and maintain production levels. With the current oil price, the goals and targets become very tough and you need to manage the job within this new required budget.

Some of the targets we are working towards relate to managing people and also to health and safety operations. Recruitment is a challenge. Currently there are five process engineers working under me. Under these current conditions it is very difficult now to find professional and qualified engineers.

What health and safety issues in particularly is the company currently focusing on?

YAT.We constantly review operation parameters in health safety and procedures and initiate procedures to do different jobs. Another important task is to ensure our people are getting the right support.

What expansion plans does Dubai Petroleum have?

YAT.Currently we have shut down our facility to upgrade it and put in additional equipment and make it ready for future facilities. This work includes providing additional tie-ins for future equipment and extensions of the platform in order to install additional power generation machines, additional equipment and pumps that would enable us to handle more oil.

What new technology is Dubai Petroleum using to increase its production of oil?

YAT.Currently we are installing Electrical Submersible Pumps in the wells.

They increase the flow from the wells and enable us to gain more oil than using our traditional methods. We have installed multiphase flow meters, which measure the percentage of oil, water and gas in the facilities. We understand the operation better using these devices. There was also a project which involved looking into trying to enhance recovery using CO2 injections.

This project was handled by Shell.

What internal projects is the company working on?

YAT.The company is currently establishing a team to take care of recruiting new nationals. We have a target to reach 35 percent of nationals in this

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“The main challenge now is to effectively optimise oil and gas operations to keep on target and maintain production levels” company and so far the plan is going well. Currently Dubai Petroleum has a lot of scholarship programmes for students to join the company and they are participating in all the university career fairs in order to recruit experienced people.

Is Dubai Petroleum affected by the problem of many petroleum engineers being close to retirement age?

YAT.In Dubai Petroleum we have a lot of people who’ve been working here for over 20 years and so there will be a big gap between this new generation and these people. So we need to push for more people in order to ensure there is continuous knowledge transfer between them. n

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PIPELINE FOCUS

Replacing corroded pipelines costs upwards of US$643,000 per kilometre. Mark Byerley, President of NACE International, explains why maintaining and inspecting pipelines is vital in the battle with corrosion.

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n 2002, the US Federal Highway Administration (FHWA) released a breakthrough two-year study on the direct costs associated with metallic corrosion in nearly every US industry sector, from infrastructure and transportation to production and manufacturing. The study, entitled Corrosion Costs and PreventaMark Byerley tive Strategies in the United States and initiated

by NACE International, revealed that corrosion is the primary factor affecting the longevity and reliability of pipelines that transport crucial energy sources throughout the nation. There are more than 528,000 kilometres of natural gas pipelines, 119,000 kilometres of crude oil pipelines and 132,000 kilometres of hazardous liquid pipelines in the US, amounting to an estimated US$7 billion in average annual corrosion-related costs in monitoring, replacing and maintaining these assets.

“Given the slow and destructive nature of corrosion we are looking at replacing a kilometre of pipeline for around US$643,000 or more, which is an extremely expensive proposition,” explains Mark Byerley, President of NACE International, the leader in the corrosion engineering and science community. “Maintenance and inspection are of primary importance – at least they should be to many companies – so the driving force for that expenditure is to preserve the asset of pipeline and to ensure they operate safely without failures and jeopardising public safety, the environment and everything else that comes with that.”

The survey indicated that the primary loss of protection on the pipelines was due mainly to two factors: the degradation or

deterioration of the coating and inadequate protection levels. The major maintenance is associated with monitoring and repair problems, and in addition to maintenance there is the issue of integrity management and inspection focusing on condition assessment, corrosion mitigation, life assessment and risk modelling. “If you look at maintenance packages, you’re looking at between US$3000 and US$6500 per kilometre annually to maintain a pipeline and protect it from corrosion; compared to the offset from what it costs to replace a pipeline, you can see that the ROI is fairly extended,” says Byerley.

Following a number of high-profi le pipeline failures, public safety concerns have driven new regulations and corrosion control practices for gas and liquid transmission pipelines over the last several years. Byerley highlights the various technologies that can help in maintaining and ensuring pipelines live a long and happy life. “First of all you need to look at the materials that go into the pipeline, the types of steel you use,” he advises. “Plus there’s a coating component, making sure that the pipeline is well protected

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dielectrically from the outside elements. And we do that through various coating technologies, whether it be fusion-bonded epoxies or tape-wrap systems. There are several spray-applied type systems as well. And then we get into the electronics side, where we’re inducing currents into the field to help slow the effects of corrosion, or to mitigate them in areas where the coatings are not present.”

Byerley goes on to explain that as corrosion experts, the sector produces a different breed of engineers and with the increase in research and development, the industry is improving worldwide. “We’re one of the few disciplines in the engineering field that actually work every day to put ourselves out of a job, because once corrosion’s eliminated we’ll have nothing else to do.”

Much of the work done at NACE International continues to revolve around the US Department of Defense. However, NACE is looking at different outreaches – not just in the US pipeline market, but around the world – to help mitigate the problems, including Australia and New Zealand, as well as Europe. And as pipelines improve around the world the industry is seeing a much more aggressive use of improved data gathering, through the use of multiple technologies and coatings in conjunction with the cathodic protection ECDA (external corrosion direct assessment) and other pipeline integrity management programmes.

And as a result of the increased use of pipeline integrity management programmes, NACE has seen a rise in demand for education on these programmes too. “If you look at the lack of knowledge of senior management, it’s not a bad thing, just something that they usually don’t deal in,” explains Byerley. So getting that senior management buy-in is

a huge challenge for the corrosion department in these companies, and while there are over 21,000 NACE members worldwide, the vast majority are not even considering corrosion until a calamity strikes.

“Th rough the media staff at NACE, we have the responsibility of asking for an audience with those in senior management positions, and have done some corporate outreach programs getting people to understand how easy it is to protect pipelines – especially cost-wise – in order to try to prevent having to replace that pipeline. Today’s technologies allow us to keep pipelines in the ground for well over 100 years, as long as they’re administered properly,” says Byerley. “However, these are probably not as successful as we’d like, which is probably due to corrosion being a very unsexy topic, so it’s hard to get them in the doors at first.”

The corporate outreach programs can involve anything from tasking employees of the company to focus on their upper management teams to explain to them what they do every day, to NACE staff going to a board of directors of major suppliers, pipeline companies, oil companies, gas companies and working with senior management and teams within the company to educate the management on corrosion and its effects on their systems or assets. “Knowledge is power. And if you look at what NACE is doing in this respect, we hold 450 classes and train 9000 people per year. No one educates more people on corrosion prevention than NACE International.”

Along with education, Byerley believes that the biggest challenge in the fight against corrosion is in inspection and maintenance frequencies. The more remote or hostile the environment, the more difficult it is to get to the point of inspection or a component that needs to be maintained. “It starts at the laying of the pipeline,” claims Byerley.

“But that said, we are now doing a lot of work with remote monitoring, where the pipeline reports to a central hub via satellite or cellular communications, so we can monitor the pipeline from an office thousands of miles away.”

Byerley advises that companies looking to improve the issue of corrosion need to start getting involved in the industry and look at how they can participate. “Whether it’s getting the members of their companies involved at a local section of an organisation like NACE or whether it’s in a research committee at NACE, technical committees help drive standards that then form new education programmes,” he says. “These are just some of the more vital areas in NACE International, but there are other things like supporting an employee and furthering their education on corrosion prevention, whether they get involved in formal training or attend conference and technical symposiums.”

Moving forward, it is clear that increasing research and development, as well as furthering education, could dramatically improve the issue of corrosion in the US and around the world. While technological advancements are happening all the time, the best way to prevent corrosion involves better corrosion management through preventive strategies in both non-technical and technical areas.

“The best way to prevent corrosion involves better corrosion management through preventive strategies in both non-technical and technical areas”

Preventive strategies • Increase awareness of significant corrosion costs and potential cost savings • Change the misconception that nothing can be done about corrosion • Change policies, regulations, standards and management practices to increase corrosion cost savings though sound corrosion management • Improve education and training of staff in recognition of corrosion control • Implement advanced design practices for better corrosion management • Develop advanced life-prediction and performanceassessment methods • Improve corrosion technology through research, development and implementation Source: www.nace.org

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EXECUTIVE INTERVIEW

Striving for integrity With pipeline corrosion costing the oil and gas industry billions of dollars in repairs and lost production, O&G speaks to expert Richard Norsworthy about preventative measures.

What are the main challenges today when it comes to pipeline integrity as related to external corrosion?

Richard Norsworthy. Though pipeline companies are doing a better job with cathodically protecting their pipelines, there are still many who misunderstand the use of pipeline coating in conjunction with cathodic protection. Many companies are still using types of pipeline coatings that shield cathodic protection current when the coating loses adhesion which allows water to penetrate and corrosion to develop. The amount and rate of corrosion will be dependent on several variables, but some coatings have developed a reputation for shielding cathodic protection when disbondments occur. Th is continues to be one of the main reasons for external corrosion on cathodically protected pipelines today. There are some coating types that will allow cathodic protection to be effective when disbondments occur, allowing the cathodic protection current to effectively protect the pipe surface under the coating.

How has the understanding of the interaction of cathodic protection and coatings evolved over the years?

RN. Many do not understand the relationship between cathodic protection and coatings.

Nearly all coatings used for pipelines today are good dielectric barriers that allow cathodic protection to spread and protect many miles with minimal current requirements.

The question is why the industry still has external corrosion on cathodically protected and coated pipelines. Cathodic protection does not usually cause coating failures with these coating systems. The reasons most coatings disbond or fail are poor coating selection, surface preparation and application.

Soil stress issues affect many types of coatings. Cathodic protection can damage some coatings, but most blistering and coating damage on cathodically protected pipelines is not caused by cathodic protection. The cathodic protection just accelerates the failure.

What would be some best practices that one could recommend to a buried pipeline operator?

RN. When possible select coating types that will not shield cathodic protection currents if coating adhesion fails. These are called non-shielding coating systems. The coating types that have a proven history of non-

shielding are fusion bonded epoxies (FBE) and the Polyguard RD-6 coating systems. Though these coatings may not be totally non-shielding in all situations, they both have proven field history, with laboratory testing to back up these claims. FBE has more than 50 years of service life and the RD-6 now has over 22 years of field service. There have been many internal line inspection tool runs in the pipes coated with these two coatings, yet it is rare to ever fi nd external corrosion under either of the coatings when disbondments occur. It is also rare for these coatings to disbond when properly applied. Therefore, water under these coating types has not been a major problem. In the United States, the Department of Transportation has issued CFR 192.112 (2008) mandating nonshielding coatings if operators want to increase their operating pressure.

If a coating company claims to have a non-shielding coating type, ask for their proof. Do not just take their word for it, scrutinise it.

Could you give an example of where your services and expertise aided a client with guarding their pipelines against corrosion?

RN. As mentioned above, the Polyguard RD-6 coating system has a very successful history with no reports of measurable external corrosion under the rare, known disbondments. As more companies fi nd disbonded and shielding problems with other coating systems such as shrink sleeves and solid fi lm backed tape systems, the RD-6 system is becoming the field applied coating system of choice for rehabilitation and girth weld coatings on new pipelines. The RD-6 system requires less surface preparation, is easier to apply and can be immediately back fi lled versus two part epoxies. Our market share is growing worldwide as more and more corrosion control engineers learn that there are choices when it comes to field applied coatings. When selecting pipeline coatings, the non-shielding properties of a coating system may be more important than most other properties normally considered. „

Richard Norsworthy has published numerous papers on corrosion control, and authored the chapter on Coatings for Underground or Submersion Service in Uhlig’s Corrosion Handbook. He is a NACE instructor for courses in basic corrosion, CP, and coatings used in conjunction with CP. In 1995, he started Lone Star Corrosion Services, which became part of Polyguard Products in 2007.

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GAS INSIGHT

IRAN RISING Natural gas is gradually becoming the basis of a new worldwide strategy for creating a cleaner and more secure future with the sector awaiting tremendous growth over the next two decades. Despite economic sanctions over its controversial nuclear programme, Iran – the country with second largest natural gas reserves in the world after Russia – is preparing itself to become a major player in the global gas business.

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t a time when US and Europe are devising plans to further weaken Iran, the last few months saw this Middle Eastern country taking major steps to boost its economy by positioning itself as an essential energy supplier to hundreds of millions of people. Even the slow progress in finding partners to develop major gas fields in south Iran doesn’t constitute an obstacle for the country’s ambitious plan to become a major gas and LNG exporter in Asia – something that is helped by its geographic position and neighbours like Turkmenistan, the country that after decades of selling gas solely to Russia is now seeking to diversify its transport routes to the world market and has found an ideal partner in Iran.

Turkmenistan, with 2.86 trillion cubic metres of natural gas, is thought

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to hold the world’s 12th largest proven reserves, although estimates from GCA (Gaffney, Cline & Associates) claim that the actual figure is three times higher, placing the country in forth place worldwide after Russia, Iran and Qatar. So it was no surprise that Iran decided to use Turkmen gas to supply its northern provinces, located too far away from its massive gas fields in the south, and free up more of its own gas for exports.

The first of the pipelines to connect Iran to Turkmenistan was the $190 million Korpeje–Kurt Kui pipe which was launched in December 1997 and became the first natural gas export pipeline in Central Asia to bypass Russia. Under the 25-year contract’s terms, Iran annually takes about eight billion cubic meters (bcm) of natural gas from the Turkmen Korpeje field. The second pipeline was opened in January 2010 at an inauguration ceremony in the desert near the Iranian border. The 182km

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Pakistan pipeline. After 14 years of negotiations, in May last year Iran finally signed a deal to connect its economy with its eastern neighbour and export some 150 million cubic metres per day from South Pars, the world’s largest gas field shared by Iran and Qatar. Both Iran and Pakistan hope to extend the pipeline into India and perhaps into China which would not only give Iran a foothold in the Asian gas market, but also provide it with an economic lifeline and the diplomatic protection that energy-dependent economies typically grant their suppliers.

Iran’s second export project is the Persian Pipeline or Iran–Europe pipeline which will connect South Pars with Turkey, Greece, Italy and other European markets. With an overall length of 3300 km and the an-

Countries with the largest natural gas reserves

Russia – 47.6 Iran – 29.6 Qatar – 25.5 Saudi Arabia – 7.4 USA – 6.9

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Dauletabad–Sarakhs–Khangiran pipeline with an initial capacity of six bcm per year (later to be increased to 12 bcm) connects the Dauletabad gas field in Turkmenistan with Khangiran refinery in Iran.

This recent Turkmen-Iranian pipeline mocks the US Iran policy which desperately seeks to isolate the country. That policy suffered another blow this year when Iran’s other neighbour, Azerbaijan, also announced plans to build a new gas pipeline to Iran by 2012 with the annual capacity of 6.57 bcm. The construction of the 200 km Sangachal– Azadkend–Astara pipeline can start as soon as in April this year. All these potential 20-27 bcm of gas imports put Iran in a great position to start work on its many other ambitious export pipeline projects in a task to create a new axis of power in the region.

First in the line of export pipelines is a proposed 2100km Iran–

nual capacity of 37 bcm of natural gas per annum, this pipeline is looking to rival the EU-supported Nabucco project and expected to be operational by 2014.

Both projects require massive investments, however the long-term profits for Iran can be huge especially in the Asian direction where countries like India and Pakistan have low gas reserves and where energy demand exceeds supply. As another step in the process of becoming a key player in the gas market, Iran has announced plans to further develop its domestic natural gas infrastructure with Tehran spending US$9 billion in the next five years on the construction of 3000-7000 miles of pipelines inside the country and 20-22 pressure control stations.

Whether Iran’s natural gas ends up powering turbines in New Delhi, Karachi, Beijing or Vienna, one thing is certain: Iran will be richer and more geopolitically indispensable. As in the case of US dependence on Saudi Arabia, China’s on Sudan or Germany’s on Russia, energy dependency is a major driver of foreign policy. Once these new gas conduits are established, it will be far more difficult for the United States to gather international support for policies aimed at reigning in Iran. And with recently announced investments, agreements and contracts Iran is steadily on course to become a key gas exporter for decades to come. n

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PIPELINE INTEGRITY

Cracking the corrosion code PPSA members Thomas Beuker of the ROSEN Technology and Research Center (RTRC) in Germany, Bryce Brown of ROSEN USA and Mohammed Jaarah of ROSEN Saudi Arabia, describe the results of a survey into the use of Electro-Magnetic Accoustic Transducer technology to help combat stress corrosion cracking.

R

ecognised as a major integrity threat since the 1970s, the phenomenon of Stress Corrosion Cracking (SCC) forms an important part of integrity management programmes worldwide.

Whereas SCC has conventionally been detected with liquid coupled ultrasonic technology, advances made in recent years in ultrasonic systems based on an Electro-Magnetic Acoustic Transducer (EMAT) mean that this technology now has the potential to be established as a preferable alternative. Dispensing entirely with the need for a liquid coupling means EMAT is a highly cost-effective inspection method for gas pipelines in particular. Th is article presents a summary of the field tests conducted to establish the suitability of highresolution EMAT technology in assessing SCC and similar threats in pipelines.

Test approach and nature of EMAT The process of qualifying an inspection technology for a specific type of defect is typically based on three criteria: sensitivity to sub-critical flaws (refer to Figure 1), depth and length sizing accuracy, and defect characterisation capability. ROSEN used these criteria in a test series conducted to initiate the quali-

fication process for EMAT as an inspection technology suitable for crack detection and assessment in gas pipelines.

Inspection tools incorporating EMAT technology usually consist of two measurement units to achieve complete coverage of the internal pipeline surface and a sufficient number of sensors to support high-resolution analysis of cracks and crack colonies (see Figure 2). Since EMAT-based inspection tools provide a detailed view of the dimensions and distribution of the detected anomalies both around the circumference and along the pipeline axis, they greatly facilitate the subsequent evaluation process.

Sensitivity The sensitivity threshold for individual cracks accepted throughout the pipeline industry is 30 mm (1.18”) in length and 1 mm (0.039”) in depth. A combination of artificial and natural crack-like indications was studied following inspection with the EMAT tool. The minimum dimension detected with EMAT technology was found to be 20 mm (0.79”) in length and 0.65 mm (0.026”) in depth with a probability of detection (POD) of 92 percent.

The analysis conducted proves conclusively that the sensitivity of EMAT is comparable to more established inspection technologies and notably that the target for detecting subcritical flaws is met.

Depth and length sizing capabilities A depth-sizing model based on electromagnetic acoustic inspection was developed by ROSEN as part of the test project. This model incorporated a quantitative multi-parameter process whereby various parameters derived from the datasets, e.g. amplitude and frequency content of the different wave modes, were correlated to the depth of a crack indication. This model was then applied to artificial crack-like flaws as well as natural cracks and SCC. The accuracy levels achieved in these tests was found to be +/- 0.64 mm (0.025”) with a confidence level of 90 percent. This result is comparable to that of widely accepted crack evaluation processes based on other inspection technologies. Beside the depth of a crack, its length is an essential parameter for integrity assessment. A threshold criterion is used on the signal amplitude to determine the length of a flaw. Sizing results for artificial defects of different length are shown below; even for short defects, a stable length sizing can be achieved. However, due to the physical size of the applied shear wave, short features result in a slightly larger scattering of the length measurement.

Defect characterisation and coating assessment Over and above the criteria of sensitivity, depth and length sizing, the ROSEN

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EMAT

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log distance (mm) Figure 1: Sensitivity of EMAT technology. The graph correlates a manual UT depth profile with the profile of the integrated EMAT amplitude. This example is taken from an excavation campaign following an EMAT inspection survey.

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EMAT Depth (mm)

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Manual UT Depth (mm)

Amplitude EMEA (a.U.)

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test programme also investigated the ability of EMAT to characterise different types of defects. Since both risk assessment and corrective measures directly depend on the types of defects present in a pipeline, their reliable identification plays a vital part in asset integrity management. Adopting a multi-parameter correlation model (MPC) taking into account the distribution of the responses to a particular feature type, EMAT was applied to a sample set of 315 crack-type and non-crack-type defects. Field verification subsequently revealed that the probability of identification (POI) for these fl aws was as high as 91 percent.

Apart from direct defect characterisation, the ability to identify pipeline-coating types is helpful, since some coating types are more prone to stress corrosion cracking (SCC) than others. Additional information on the condition of the coating is also directly relevant to crack-type defects, since coating disbondment is demonstrably a precursor of SCC. The tests revealed that the EMAT inspection system is capable of providing dependable information on both coating type and condition. Identified on the basis of changes in transmission amplitude received through multiple signal channels, the precise position and even lateral dimensions of disbonded areas are reported.

Conclusion

4 3

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Given Depth (mm) Figure 2: Application of the EMAT sizing to a population of artificial flaws in a 16” test joint.

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For the purpose of initiating the qualification process for EMAT as an adequate inspection method for crack detection in gas pipelines, ROSEN conducted a series of empirical tests. These tests confi rmed the high sensitivity of EMAT even to sub-critical fl aws and its excellent depth and length sizing capabilities, which are on a par with well-established technologies. In addition, EMAT accurately characterised defects and furnished precise and dependable information on the type and condition of pipeline coating encountered. In sum, the sensitivity and accuracy of EMAT inspection systems are the basis for a subsequent application of integrity management programs. Th is has been described as exemplary using the API 579 assessment standard.

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DIARY DATES 142 The most high profile oil and gas events happening around the world in the next six months.

APRIL 2010

Apr 12 - Apr 13 7TH AFRICAN PETROLEUM FORUM 2010 The Geological Society, London, UK

Apr 13 - Apr 15 OFFSHORE AUSTRALASIA CONFERENCE 2010 Burswood Conv. Center, Perth ,

Australia

MAY 2010

May 13 - May 14 BLACK SEA SECOND OIL AND GAS SUMMIT (BSOGS 2010) Ceylan Intercontinental, Istanbul, Turkey

May 17 - May 19 OGEKU 2010, KUWAIT INTERNATIONAL OIL, GAS & ENERGY EXHIBITION Safir Hotel International, Kuwait

May 20 - May 21 8TH ASIA PETROCHEMICALS STRATEGY & TECHNOLOGY CONFERENCE (APTC) Parkroyal Hotel, Kuala Lumpur, Malaysia

JUNE 2010

June 21 - June 24 WORLD NATIONAL OIL COMPANIES CONGRESS Grange St. Paul’s Hotel, London, UK

Jun 28 - Jan 7 ERBIL OIL&GAS CONFERENCE AND EXHIBITION International Fair Ground, Erbil, Iraq

SEPTEMBER 2010

Sep 12 - Sep 15 AAPG 2010 INTERNATIONAL CONFERENCE & EXHIBITION TELUS Convention Center, Calgary, US

Sep 16 - Sep 19 OIL & GAS INVESTMENT ASIA 2010 Singapore

Jun 1 - Jun 3 NEXT GENERATION OIL & GAS - LATIN AMERICA

Sep 27 - Sep 30 CLEAN TECHNOLOGY INVESTMENT WORLD ASIA 2010

InterContiental Resort, Playa Bonita, US

Conrad Hotel, Hong Kong

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OCTOBER 2010

Oct 3 - Oct 5 PETROTECH 2010 9TH INTERNATIONAL OIL AND GAS EVENTS AND CONFERENCE New Delhi, Delhi, India

Oct 5 - Oct 8 KAZAKHSTAN INTERNATIONAL OIL & GAS EXHIBITION AND CONFERENCE Atakent Exhibition Centre, Almaty, Kazakhstan

Oct 12 - Oct 14 OFFSHORE MIDDLE EAST Qatar Int Expo Centre, Doha, Qatar

Oct 19 - Oct 21 DRILLING & COMPLETING TROUBLE ZONES FORUM Galveston Convention Cent, Galveston, Texas, US

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PHOTO FINISH 144

A fire lit by employees of French oil giant Total burns at the Feyzin Refinery in Southeastern France on February 19. A call by workers for an “unlimited strike” at six Total oil refineries sparked fears of possible supply cuts as some of the plants face closure.

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