Senators raise concerns on oil sands pipeline

By Ayesha Rascoe

WASHINGTON (Reuters) – Nearly a dozen U.S. Senators on Friday raised questions about the need for a proposed $7 billion pipeline that they said will bring “dirty oil” from Canadian oil sands to U.S. refineries and significantly increase the country’s reliance on fossil fuels.

The lawmakers, 10 Democrats and one independent, said the State Department needs to answer several key questions before deciding whether to approve TransCanada’s application to build the 2,000-mile Keystone XL pipeline.

“Approval of this pipeline will significantly increase our dependence on this oil for decades,” the senators said in a letter to Secretary of State Hillary Clinton.

“We believe the Department of State should not pre-judge the outcome of what should be a thorough, transparent analysis of the need for this oil and its impacts on our climate and clean energy goals,” the letter said.

Led by Democrats Patrick Leahy, of Vermont, and Jeff Merkley, of Oregon, the letter said the department should examine whether greater use of fuel-efficient technologies and advanced biofuels could offset the need for the pipeline.

The department should also consider whether expanded use of oil sands crude will harm U.S. attempts to reduce oil consumption, the lawmakers said.

This is the latest in a series of critiques that various lawmakers have lobbed at State as the department considers whether to greenlight the Keystone project, which is expected transport 510,000 barrels per day of crude from Alberta to the U.S. Gulf coast.

Clinton angered some lawmakers and environmental groups this month when she said her department was “inclined” to approve the pipeline because of energy security issues.

A senior State Department official told Reuters this week that no final decision had been made and that input from the Environmental Protection Agency and other federal agencies would be fully weighed.

Critics of the pipeline say it threatens the environment and will boost U.S. dependence on a dirty fossil fuel instead of moving toward renewable energy sources. Canada’s oil sands, the largest source of crude outside the Middle East, use open pit mines and processing plants that emit carbon dioxide.

Crude produced from oil sands emits more carbon over its life cycle than other oil burned in the United States, but experts disagree on how much more.

“The Keystone XL pipeline is an environmental disaster in the making,” said Alex Moore, of green group Friends of the Earth. “The threat of spills…and the additional air and water pollution it would unquestionably make this pipeline dangerous for people all along its path.”

Supporters say the project will ensure a stable source of oil and lessen dependence on oil from the Middle East and Venezuela.

Nebraska Senator Mike Johanns and other Nebraska officials have raised concerns about the pipeline’s proposed route through the Ogallala aquifer.

The group of Senators led by Leahy and Merkley also asked whether the department had considered what impact the pipeline would have on the water reservoir, which spans eight states and yields nearly a third of water for U.S. irrigation.

(Reporting by Ayesha Rascoe; Editing by David Gregorio)

WASHINGTON | Fri Oct 29, 2010 4:20pm EDT

Comment by a former employee of Shell Oil USA

I read your article on ‘dirty oil’ and the political opposition to a pipeline from Alberta to the US.

What can I say, except – ‘Angels and ministers of mercy deliver us. Those fools in Washington are at it again.’

Given the current rate of increase in world wide oil consumption, and the fact that the public of the world is in general pretty indifferent/oblivious to the environmental effects of that consumption, I see absolutely no alternative to the development of the oil sands of both Canada and Venezuela. Not in the short term, nor in the long term either.

Failure to develop those resources will simply mean we increase the rate of consumption of the so-called ‘clean oil’, which is not so clean, by the way. Conventional sources of oil produced in remote regions of the world are also very ‘dirty’ because the gases associated with their production are usually flared and not re-injected onto the producing reservoir. Flaring of production related gases is a major contributor to environmental methane releases (through incomplete combustion) and CO2.

In reality, because there is so much ‘oil’ to be found in the non-conventional tar sands and heavy oil sands these ‘unconventional’ sources of hydrocarbons are going to play an ever increasing role in providing the oil this energy hungry world will demand over the next 100 years. Natural gas will likewise provide an increasing role in meeting that demand.

That article simply serves to highlight the appalling level of ignorance of US political leadership as it pertains to the energy industry and the requirements necessary to meet world wide energy consumption/production demands, now and in the future. Those people are absolutely clueless as to the realities of what is necessary to fuel the modern industrial world, and the level of extensive capital investment it will take to reduce the level of hydrocarbon based fuels the world currently consumes. They are not only appallingly ignorant of the facts, their ignorance (along with political arrogance) makes them incompetent, even dangerously incompetent, when it comes to making rational decisions regarding US energy policy.

Contribution from a former employee of Shell Oil USA

Both the UK and the US have statutes entitled: ‘Trading with the Enemy Act’. The UK’s was passed in 1939 and the US’s in 1917.

Royal Dutch Shell’s army of attorney’s have obviously found loop holes in these and other statutes that allow Shell to continue to trade with Iran. That trade is of far greater value to Iran than it is to Shell, for it gives Iran the means to continue with their weapons development programs.

Perhaps it is time for the UK Parliament and US Congress to plug some of those loop holes to prevent the kind of conduct Royal Dutch Shell finds so profitable.

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An analysis of the sequence of events on the 20th April which led to the disaster on Deepwater Horizon

By Bill Campbell, Retired HSE Group Auditor, Royal Dutch Shell.

Operating Blind in Deepwater

Only minutes before the blowout on Deepwater Horizon on 20th April everything was reported as being in order.  The negative pressure test of the integrity of the well had been good and the displacement of seawater after this test was going fine.

But just 25 minutes after this reassuring message was passed to the senior toolpusher, mud started to overflow from the well onto the drill floor.  With only seconds to act and do the right thing mistakes were made which allowed gas to be ingested into areas of the rig where sources of ignition were present.  Actions that could have been taken to prevent the ignition of the gas were not taken and four minutes after the blowout commenced most of the crew, on or near the drill floor, were killed in the first explosion.

How all this could have happened on a modern deepwater exploration rig, with an experienced crew, and with sophisticated means at their disposal to monitor the well continually is covered in this article.
______________________________________________________________

21.20 hours: Minutes from Disaster everything was fine

At 21.20 hours the senior toolpusher called the toolpusher at the drill floor to ask how the negative pressure test had gone.  The toolpusher responded that the test result was good and that the displacement of seawater from the well was going fine.

In reality however, this confidence was misplaced and would prove fatal.  The negative pressure test results had been misinterpreted and as a result hydrocarbons had been flowing into the well from the reservoir for some time.

21.38 hours: Hydrocarbons pass BOP and enter Riser

18 minutes after the reassuring message was given from the drill floor it is estimated that the hydrocarbons had passed the top of the well flowing past the BOP located on the seabed and entered the riser.  It had only 5000 feet to flow to reach the surface.

As the oil with its associated gas in solution flowed to the surface the gas would have vaporised as the internal pressure dropped with the gas expanding exponentially as a consequence of this pressure drop.  The gas, acting as a propellant, would have accelerated the mud and oil forward with ever increasing velocity. 

21.42 Hours: Mud overflows onto the drill floor

Just minutes after the hydrocarbons were estimated to have passed the BOP to enter the riser, and just 22 minutes after the initial assurances were given to the senior toolpusher that things were going fine, the mixture of oil, mud, and gas reached the surface. Mud initially overflowed onto the drill floor but within seconds was being projected an estimated 200 feet into the air.

As all hell breaks loose, mistakes are made

Taken it would appear, completely by surprise, the drill crew may have thought that they were experiencing yet another kick that could be controlled, and took another fatal decision.  Rather than maintaining the surge flow via the surge diverter (designed for that very purpose), and which was correctly aligned to route fluids overboard in such emergencies, they instead manually intervened to direct the flow to the mud gathering system.  This low pressure and flow system was overwhelmed and the gas in the mud stream was then vented from this system directly onto the rig.  Only 25 minutes after the earlier reassuring call received by the senior toolpusher he was now told that the well was blowing out.

Attempts were made from the drill floor to close the BOP but these failed.  Two minutes later the gas alarms started to go off with gas rapidly dispersing throughout the rig and within another two minutes the first explosion occurred followed 10 seconds later by a second explosion.

How could this have happened?

What makes this story so incredulous is that this was a modern rig.  It had an experienced crew who had previously experience kicks with what was a troublesome well and had been asked by the Regulator to proceed with caution.  As an exploration rig drilling operating in deepwater it had sophisticated systems to monitor inflow into and outflow out from the well but yet they the drill crew were apparently totally unaware that a blow-out was developing for 60 minutes or so before mud started flowing onto the drill floor.

The well monitoring system was also designed to measure gains or losses of mud in the active mud pits by constantly measuring pit levels during well operations.  Alarm settings on these pit levels could be adjusted by the mudlogger so that if certain criteria were exceeded these alarms would provide early warning to the logger and the Driller that something was amiss.  The monitoring of the well as described here was a mandatory requirement of the TransOcean Well Control Manual.   So just how could the Driller and mudlogger be unaware that the reservoir fluids had been flowing into the well for some time with all these precautionary measures in place.  What went wrong?

The answer to this lies in the detail of the BP report supported by testimony given by Sperry-Sun (whose systems monitored and retrieved considerable data from ongoing well operations this data being available in real-time onshore as well as offshore and who employed the mudloggers) to the joint Inquiry board.

For many hours the crew were operating blind

After the completion of the positive pressure test and before commencement of the negative pressure test a number of simultaneous operations commenced on the rig that influenced the safe and effective monitoring of the well.  The Sperry-Sun engineer gave a detailed post mortem explanation of data held in the memory banks of their systems to the Joint Inquiry Board.  The data indicated to him that for most of the day, and with respect to the monitoring of the well, the drill crew and mudlogger had been in his words operating blind.

Operations carried out simultaneously with the integrity testing of the well prevented well monitoring at critical times

The die was apparently cast when at 13.28 hours Deepwater Horizon started offloading drilling mud to the M/V Damon Bankston.  The mudlogger was apparently concerned about this and told the assistant driller that mud pit levels could not be monitored during offloading.

In reply, the assistant driller told the mudlogger that notice would be provided when offloading ceased but according to testimony given to the Inquiry by Sperry-Sun, and as stated in the BP report, this did not happen.

At 1600 hours up to 17.50 hours another simultaneous operation took place related to the cleaning out of the trip tanks.  During this period recorded flow data from the well was unreliable.

Offloading to the vessel ceased but the mudlogger was not aware of this

At 17.17 hours offloading ceased but the mudlogger was not notified and therefore no actions were taken to re-install the well monitoring system and its associated alarms.  With no effective well monitoring ongoing the negative pressure test was completed by 1955 hours.  This test involved a controlled underbalancing of the well.  The BP report estimates that continual flow into the well from the reservoir started around this period when the seawater used to underbalance the well was being circulated out.  Thereafter, and up to the time when the mud started spewing out into the drill floor, no monitoring of the well by the mudlogger, or it appears any other competent person, took place.

Herein may lie the explanation of why the drill crew were so taken by surprise it would seem being totally overwhelmed by the events in those crucial minutes and seconds prior to the explosion.

With only seconds to Disaster eleven men need not have died if appropriate actions had been taken

Even at this late stage in the evolving catastrophe, and despite the failure of the BOP, 11 men need not have died.  At 21.47 hours the first of many gas alarms sounded.  This was still 125 seconds before the gas was ignited when ingested into the Power Generation engine rooms No 2 and 3.  These were the on-line Generators and in these switch-rooms and engine spaces there were unfortunately, many sources of ignition.

The rig as designed allowed gas to enter areas where sources of ignition were present – no automatic systems were available to prevent this

Although there were combustible gas detectors in the air intakes to these rooms, the operation of these detectors (by design) took no executive action to shut down the power generation or the associated ventilation systems, including the closure of the fire dampers.  These areas were simply not protected against gas ingress.

To protect such areas in the event of a gas accident, manual intervention was necessary, but none was taken

On the drill floor there was apparently a means to manually shutdown these unprotected areas where sources of ignition were present with the instruction to be used in a gas accident. The BP report indicates this facility was not used, the drill crews attention not surprisingly being focussed on the emergency.

In testimony to the joint Inquiry, the officer on watch in the bridge, whose principal duties appeared to be related to marine aspects such as the rig’s dynamic positioning system observed the gas detectors going into alarm and accepted these alarms.  She instigated the general platform alarm and made a number of public address announcements but took no action to trip the power generation and thus shutdown the ventilation to non-hazardous areas such as Engine rooms and associated switch-rooms.   It was not clear to me in listening to her testimony whether the facility to do this was located on the bridge but I suspect it was.  The chief mate, or master of the vessel, was also on the bridge with her but he also took no actions as described here.

If Power Generation had been tripped manually the explosion could have been avoided

If action had been taken to trip and thus shutdown power generation at this crucial time when the initial gas alarms sounded it is likely that the explosion could have been avoided.  There is an important point to be made here for persons who in the future – after deepwater drilling commences again – have to assess the hazards of operating in deepwater.

Operation of the BOP may not have prevented the explosion

Even if the BOP had operated perfectly the explosion was unavoidable given the action taken. If the BOP had functioned as designed the environmental disaster would have been averted.  However, there was circa 5000 feet of riser above the BOP (the riser being for all intents and purposes a vessel containing hydrocarbons under pressure with a volume in excess of 2000 cubic feet) which was open to atmosphere at the surface.  This would have created the same gas cloud conditions when the flow was diverted to the low-pressure mud gathering system, as it was.

If the BOP had closed, the only way the explosion could have been avoided is if the flow had remained aligned to a surge diverter. Under such conditions the gas would have been dumped into the atmosphere and being mainly methane (lighter than air) would have rapidly dispersed with the wind taking it away from the rig, if the rig was upwind of the diverter outlet.   To cater for wind directions this exploration rig had two surge diverters, port and starboard.

Why was there no automatic actions taken by the gas detection system to trip Power Generation

There is another important point to be made here for persons who in the future – after deepwater drilling commences again – have to assess the hazards of operating in deepwater.  Following the deaths of 167 persons on Piper Alpha some 22 years before this incident it became a requirement in the UK that on detection of gas at circa 20% of the explosive limit Power Generation was to be tripped to reduce sources of ignition.   Further areas such as the Engine Rooms on Deepwater Horizon (testimony indicates the seat of the explosion) were to be protected from ingress of gas by the automatic tripping of ventilation systems to these areas and the closure of ventilation inlets and outlets.  On Piper Alpha the explosion had resulted from gas being ingested into an area where sources of ignition were present.

None of these measures existed on Deepwater Horizon.

Conflict of interest between Hazards – loss of Power Generation on Deepwater Rigs means loss of dynamic positioning

Mobile drilling rigs operating in shallow water up to 500 feet or so are secured on location by a number of chains anchored to the seabed.  These rigs have automatic chain tensioning systems to keep the rig on location within given design criteria taking into account the likely weather and sea conditions under which the rig would be expected to carry out routine operations.  If there were a loss of power generation on these rigs the vessel is held on location and would not drift under the influence of current, tide or wind.  So loss of Power Generation does in itself not cause a hazard to the rig.  However the Deepwater Horizon, operating in water depths of 5000 feet plus did not have such an anchoring system.  It had some 42mW of installed power generation capacity which provided adequate redundancy such that there would be a reliability of this supply to the rig dynamic positioning system required to continually hold the rig on its exact location within designated design criteria.

A recognised hazard for this type of vessel is loss of power generation, for whatever reason.  Under these conditions the vessel will drift and the Emergency Disconnect System (EDS) would require to be operated to disconnect the riser from the BOP.  If the EDS system operated as designed the rig would be left drifting still connected to its riser with the obvious hazards associated with this.  As the BP report suggests this is likely the reason why designers were reluctant to trip Power Generation automatically on confirmed gas detection. In essence you had two critical safety related issues that were in conflict with each other.

In Summary

On the 20th April, and this raises questions about planning and what was discussed at the morning meeting with the onshore management, apparently too few crew attempted to do too much with simultaneous activities impinging on the safe completion of each other. All this on a rig that had had serious problems with this well including gas releases and that had been advised to exercise caution by the Regulator.  What effect did the visit of the VIP’s have, for at critical times there appears from the BP report to have been inadequate supervision at the work-site during critical stages of the operation.  The VIP visit was perhaps a distraction that could have been avoided on this busy day.

On Deepwater Horizon inexplicably, despite the negative pressure test indicating beyond reasonable doubt that there was influx into the well, and due it seems to human error and confusion, allied with deviation from fundamentals this test was assumed to be successful when it was not.   All that subsequently happened stemmed from this assumption with a sequence of events leading to disaster.

In my opinion this event is not so much about the well as designed but the well as installed. Installing a well is similar to any other civil engineering project in that what is installed has to be tested or commissioned before it is put into use, just as you would test a vessel or pipeline designed to contain hydrocarbons under pressure.   Wells, which are discovered to have a problem during integrity tests indicating for example a connection between the well and the reservoir, are worked over to rectify the problem and in a few hours after remedial activities have been undertaken, the integrity testing is re-commenced.  The Joint Board of Inquiry no doubt will highlight some factors that give some sort of explanation for the error of judgement re the negative pressure test.  For example that there was no detailed test procedure, that the way the test was to be carried out changed in midstream, and that there is actually no test criteria for what represents a successful negative pressure test.  And all this compounded by the fact that for a prolonged period, and in deviation of the rules of and procedures laid down by TransOcean, the well was not adequately monitored for many hours prior to the disaster.  There were also no detailed procedures or training given to the crew on how to handle the emergency that took them by surprise on the drill floor that fateful day.  That this was negligent on the part of TransOcean is indisputable.  It may be argued, in future criminal proceedings to have amounted to gross negligence on the part of TransOcean the owner and operator of the rig, we will have to wait and see.

Canadian oil sands field starts production and projects are planned in the Gulf of Mexico – where BP’s Deepwater disaster has so far cost Shell $115m

Tim Webb: Friday 29 October 2010

Trucks carry loads of oil-laden sand in Alberta, Canada, where Shell has 13 projects scheduled to come on stream. Photograph: Jeff Mcintosh/AP

Shell nearly doubled earnings in the last three months thanks to higher oil prices and production as new ventures came on stream. Excluding write-offs made for accounting purposes, its earnings were $4.9bn (£3.1bn) for the three months to September, compared with $2.6bn the previous year.

During the quarter the company began production at its oil sands mine in Jackpine, northern Alberta, part of its programme to add another 100,000 barrels a day from these operations. Jackpine is the fifth start-up of 13 projects that have been approved and are scheduled to come on stream this year and next. Shell hopes they will allow it to achieve its target of increasing its 2009 production by 11% by 2012. The company has spent $190bn in its operations since 2004 – almost double the capital investment over the preceding five years – which it hopes will reverse several years of falling production.

It said that it had also approved two new major projects, including Mars B, a deepwater project in the Gulf of Mexico which will eventually add another 100,000 barrels a day production.

The company plans to sell $7bn- $8bn of assets this year and next as it switches out of older producing fields and invests in new ways of producing gas, such as shale gas and coal seam gas, as well as investing in oil sands and in new regions such as Iraq.

Oil and gas production increased by 5% compared with last year to just over 3m barrels a day; sales of liquefied natural gas rose by 22% while the volume of refined oil products it sold was also up. Production was also higher in Nigeria, due to new projects there coming on stream and improved security.

Shell finance director Simon Henry said that it would be unlikely that the Nigerian government would provide its share of the investment needed to develop these fields, so it made sense to sell them to someone who would. Shell has so far sold three of its 30 onshore licences in Nigeria and there have been reports that bidders are circling a further $4bn of its assets up for sale there.

Henry also outlined the cost from BP’s Deepwater Horizon disaster. The moratorium on deepwater drilling in the US was lifted last month, but Henry said that it had cost the company $115m in total so far, $59m of which was accounted for in the third quarter and that more charges would be booked in the next quarter. Shell had to idle five rigs and four platforms during the moratorium.

He did not comment on whether Shell would be pursuing BP and any other companies involved for damages. He said that this year Shell’s production was 10,000 barrels a day lower than it would otherwise have been without the moratorium. Next year, production would be at least 40,000 barrels lower, and operations could continue to be affected into 2012.

The moratorium meant Shell had to suspend its drilling programme, which is now behind schedule. Its giant Perdido platform in the Gulf, for example, is still only producing around 10,000 barrels a day, despite having a capacity to produce 10 times that figure. The company also had to delay its controversial Alaska drilling programme; Shell announced this month that after the moratorium was lifted it resubmitted its application to drill off the Alaskan coast in the Beaufort Sea next year, but was holding off from a similar application for the Chuchi Sea. Henry said yesterday that it was likely that the new US offshore regulator, which has replaced the discredited MMS in the wake of the disaster, would initially take longer than the customary 30 days to review applications, which would further add to the delay in proceeding with new projects.

In the US, Exxon Mobil posted its biggest increase in third-quarter profits for six years. Net income was $7.35bn, up from $4.73bn in the same three months a year ago, due to higher oil prices, fatter refining margins and a 21% increase in production.

SOURCE

Comment by Iain Percival on Bloomberg article…

Shell Says Repercussions of U.S. Drilling Moratorium Could Last Into 2012

Messers Pals & Kennedy of Bloomberg really ought to research a topic before writing about it. Just what is meant by “Shell is targeting hard-to-reach rock formations in Australia, the U.S. and China”? Coal seams for CBM in Australia are not in the criteria of hard-to-reach. There are undoubtedly challenges in the optimal exploitation of CBM but the technology / techniques are hardly new or “hard-to-apply”. In any case the geoscience and engineering capability in Shell is more than enough to address the task. My comment applies equally well to the (presumably) tight gas assets in North America and China. The tone of the article implies Shell will have trouble delivering meaningful gas production from these “hard-to-reach” formations. Yes, the technical challenge is greater than with conventional gas, but then Shell has invested serious money in researching the technologies and techniques required. Will Bloomberg reporters write an article in the same vein throwing doubt on the ability of the BG-Group to deliver from similar formations in the same countries? One thing is for sure, the BG-Group do not have recourse to the R&D back up in-house to Shell.

COMMENTS END

The following information, links and photograph of Iain Percival are all sourced from the Internet. They were not supplied or suggested by him.

Iain Recognised for Mentoring Work

Shell retiree and former Group Chief Petroleum Engineer, Iain Percival, took the award for Outstanding Individual Achievement at the Energy Industry (EI) Annual Awards, for his work mentoring a number of young professionals, both in Shell and other organisations.

Iain is currently spending time with students and staff at RGU and the University of Aberdeen, and visits schools in his home area of the north of Scotland. Iain retired from Shell in 2006 after 33 years of service.

Iain remarked, “It is an honour I appreciate but of course I do derive a great deal of personal satisfaction from my activities.”

ROBERT GORDON UNIVERSITY NEWS NOTICE BOARD

RELATED ARTICLE: Students benefit from Shell support

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Royal Dutch Shell is assigning higher priority to its Carmon Creek in situ project near Peace River and its ongoing expansion at the Athabasca Oil Sands Project near Fort McMurray, said chief financial officer Simon Henry. Photograph by: BEN STANSALL, AFP/Getty Images

OCTOBER 28, 2010

By James Herron Of DOW JONES NEWSWIRES

LONDON (Dow Jones)–Royal Dutch Shell PLC (RDSB.LN) Thursday beat analysts’ forecasts to post an 88.4% rise in adjusted profit for the third quarter, driven by higher output and greater demand for refined products and chemicals.

The results show how the company is reaping the rewards of a lengthy restructuring focused on cost efficiency and recovering industrial demand, primarily in Asia.

“Our results have rebounded substantially from year-ago levels,” said Shell’s Chief Executive Peter Voser.

“Shell has the strongest momentum of any of the majors,” said NCB Stockbrokers analyst Peter Hutton. “On this basis we see another jump,” in Shell’s value, he said.

The Anglo-Dutch energy company said the clean current cost of supplies, a keenly-watched figure that strips out gains or losses from inventories and other non-operating items, was $4.93 billion in the three months ended September 30, compared with $2.62 billion in the third quarter of 2009. This was above average expectations of $4.32 billion in a Dow Jones Newswires poll of 11 analysts.

Sales from Shell’s refined oil products and chemicals divisions, which suffered most during the global downturn, rebounded strongly. Sales volumes of refined oil products were 4% higher year-on-year and chemical sales volumes, 13% higher. The bulk of the increase in chemical sales was related to the startup of a new petrochemical complex in Singapore.

“Asia-Pacific [downstream] has picked up quite a bit in the last six months,” said Shell’s Chief Financial Officer Simon Henry. “The U.S. remains challenging. Europe is still most definitely in a loss-making situation.”

“Shell is likely to be better than its peers…due to its greater exposure to the Far East, where refining margins improved,” said NCB’s Hutton.

Adjusted earnings at Shell’s refining and marketing division almost doubled to $1.45 billion in the third quarter, from $756 million a year earlier.

Total oil and gas production beat analysts’ expectation to rise 5.5% to 3.058 million barrels of oil equivalent per day, as new fields started up and Shell continued to benefit from improved security in the Niger Delta. The company’s Nigerian oil and gas production rose by 175,000 barrels of oil equivalent compared with the third quarter of 2009.

Adjusted profit in the exploration and production division more than doubled, benefiting both from the output increase and a reduction in costs, said ING analyst Jason Kenney. However, the company’s earnings were also supported by non-operational gains, notably higher tax credits and lower interest costs, he added.

Net profit for the quarter totaled $3.46 billion, up 6.7% from $3.25 billion a year ago. Shell’s net profit was reduced primarily by a one-off $1.13 billion charge the company took on fair value adjustments to commodity derivatives.

Group revenues were $90.71 billion, compared with $75.01 billion in the third quarter of 2009.

Diluted earnings per share were 56 cents compared with 53 cents the previous year.

At 0714 GMT Shell shares were up 0.8%, or 16 pence, at 1969p.

-By James Herron, Dow Jones Newswires; +44 (0)20 7842 9317; james.herron@dowjones.com

SOURCE

Published: Oct. 28, 2010

LONDON, Oct. 28 (UPI) — Royal Dutch Shell is still dealing with Iranian crude oil shipments under current contracts, the company’s chief financial officer said Thursday.

Simon Henry, Shell’s top financial official, said his company was still taking delivery of Iranian crude oil under the terms of its existing contracts with the Islamic republic.

The European Union and United States passed new sanctions in July that target Iran’s energy sector, though Henry said the sanctions didn’t deal with trading in Iranian crude.

“We always have and always will work with sanctions and legal requirements,” he was quoted by the Platts news service as saying.

Shell since the EU and U.S. sanctions pulled out of the downstream energy sector in Iran and stopped technical work in the upstream sector.

The company doesn’t sell jet fuel to Iranian airlines operating outside of Iran and Henry said the company stopped supplying refined petroleum to the sanction-strapped country as well.

The European Union, meanwhile, said Wednesday that its sanctions “should not affect the import or export of oil or gas to and from Iran,” Platts added.

“We need to assess the impact (these sanctions),” added Henry.

SOURCE

Shell studies oil trade impact of EU Iran sanctions

(Reuters) – Royal Dutch Shell Plc (RDSa.L) said it would assess any impact of European sanctions on its oil trade with Iran and had stopped some activities there following tougher U.S. measures earlier this year.

The European Union sanctions over Iran’s nuclear work, launched in July and which became law this week, seek to block oil and gas investment in the Islamic Republic, the world’s fifth largest oil exporter.

“Our trading business with Iran is carried out under longer-term contracts,” Shell’s chief financial officer, Simon Henry, said on Thursday. “We continue to lift (buy Iranian crude) under those contracts, but we do need to assess any implications of the European legislation.”

“It’s fair to say that the European legislation, some of which was only clarified this week, we still need to understand. There are clearly some implications around payment transactions.”

Oil industry sources have said that following the measures financial transactions with Iran have become more difficult, making it harder to pay for Iranian exports in currencies such as the euro and the dollar.

As a result, the sources say that some European oil companies have scaled back their purchases of Iranian oil this year and are reviewing whether to buy Iranian oil in 2011.

Henry said Shell always worked within sanctions and legal requirements and was stopping some business in Iran due to U.S. sanctions passed earlier this year. The U.S. measures did not apply to crude oil trading.

“The amount of activities is relatively low in materiality terms. We don’t have big investments there,” he said.

“We are withdrawing from some small downstream activities and we have been providing technical advice to some of the upstream. But that will all now stop.”

“We stopped supplying refined products last year and we’re not supplying aviation fuel outside Iran.”

Henry was speaking on a conference call after the company reported its third-quarter earnings.

(Reporting by Alex Lawler; Editing by Anthony Barker)