1. U.S. Gasoline Stocks
The average price of gasoline topped $3 a gallon Friday, amid growing concerns that refineries are simply not making enough gas to meet summer demand. Last week was a repeat of the previous 11 weeks with gasoline stockpiles falling once again, this time by 1 million barrels. Stockpiles are said to be at their lowest end-of-April level since 1956.
Last year, gasoline stocks rose steadily from late April to the end of June with weekly increases averaging 2 million barrels. Therefore, last week’s drop suggests that supplies were about 3 million barrels short of what was needed to build up stocks for summer especially with the increase in demand this year.
Although refinery utilization increased a bit to 88.3 percent, it was still below the 90+ percent necessary to cover demand. Traders, however, seized on the increase in utilization as evidence that the worst was over and bid crude and gasoline prices down.
Even though gasoline stocks are well below the bottom of the average range, the Energy Information Administration continues to maintain there is no cause for alarm. A department spokesman said stocks could be “adequate”; it just means “we would have higher prices.” Energy Secretary Samuel Bodman said last week he feared surging gasoline prices will reach a record high, but he is "reasonably confident" the market will respond to the high prices with new supply. The EIA hopes oil companies can get gasoline production back up to 8.8 or 8.9 million b/d and imports up to 1.2 million b/d during May in preparation for summer.
The EIA does not want to get into the key issue of the stockpile level at which gasoline shortages might occur this summer. The National Petroleum Council, an advisor to the US Energy Secretary, used to estimate a "minimal operating inventory level" for gasoline, but the EIA stopped publishing it several years ago "because we didn't really know what the minimum operating inventory level was."
We are now into the period when gasoline stockpiles must start registering builds on the order of 2 million barrels a week in order to avoid supply disruptions this summer. Nearly all observers agree that we will be seeing new highs for gasoline shortly and that consumer demand for gasoline is unlikely to drop in the near term. Beyond that we will have to wait for the weekly reports.
Post-election violence increased last week with 22 foreign workers seized in armed attacks within 36 hours. The latest kidnappings bring the total number of foreigners seized in the Niger Delta to at least 94 so far this year. The pace of the kidnappings has increased since 2006, when some 80 foreigners were seized in the region.
A spokesmen for the militants said that the group kidnapped on Tuesday would be returned on May 30 after President Obasanjo has left office. The spokesman also warned of future attacks on Shell facilities in the region. The Nigerian elections are deepening voter cynicism about corruption and contributing to intensified violence against the oil industry. Most observers predict government officials, along with the oil industry, will be increasingly targeted.
In one incident, South Korean and Filipino workers were taken hostage from a power plant construction site after a 40-minute gun battle between the insurgents and security guards which Korean officials say left many dead and injured.
Two of this week’s incidents involved attacks on offshore platforms and support ships, once again confirming that offshore production facilities are not necessarily safe. Following the attacks Chevron announced that it would shut down its 15,000 b/d Funiwa offshore field and the Nigerian National Petroleum Corporation (NNPC) declared a force majeure on the exports of 50,000 b/d from the Okono-Okpoho oilfield following Thursday's attack on the Mystras Floating Production Storage and Offloading vessel.
Given the number of recent attacks and the government’s reluctance to publicize the insurgents’ successes, it is becoming difficult to track just how much oil production has been shut in by the insurgency. Recent press stories, however, suggest that production now may be down about 700,000 b/d. Despite optimistic reports from Shell about restarting some shut -in production next month, little suggests that the situation will not deteriorate further.
It was a busy week in Venezuela with several developments boding ill for the future of the Venezuelan oil industry. On Monday, President Chavez announced that he would be leaving the International Monetary Fund, seemingly unaware that the action would trigger an automatic default on $21 billion in debt and allow investors to demand an immediate payback of the loans. In the past year, Caracas has issued billions of dollars of international bonds, assuring investors that the oil income would guarantee payments.
On May Day, the government took over the Orinoco upgrade projects amid much fanfare, fiery rhetoric and flyovers by Russian-built planes. Unlike the other foreign oil companies participating in the Orinoco projects, ConocoPhillips, which has the largest stake of any of the oil companies, has so far refused to sign a takeover agreement. This led to government threats that Conoco would suffer all sorts of privations and be expelled from the country.
On Thursday Chavez threatened to nationalize the country's banks and largest steel producer, accusing them of unscrupulous practices. While nationalizing American-owned assets is politically popular, nationalizing the banks would jeopardize relations with Spain.
Negotiations over the heavy oil projects are to continue until June 26. However, Conoco may have already decided that the negotiations will prove unsatisfactory. Company officials may have concluded that they will be in a stronger legal position if they simply let Chavez seize their assets without signing a partial takeover agreement. Caracas has already said it will not compensate the foreign oil companies in cash for investments worth some $30 billion.
Although the four Orinoco projects have a rated capacity of 600,000 b/d, recent output is said to be closer to 375,000 b/d. Most outside observers doubt that the Venezuelans will be able to operate or expand the projects without considerable outside help and investment. Caracas, however, says that China is ready to invest $4 billion to that end.
Chavez’s erratic behavior does not bode well for the next phase of the negotiations. He is already threatening another round of ”back tax” collections against the oil companies and is talking of suing them for mismanaging extraction. At a minimum, this week’s actions seem destined to reduce foreign investment in Venezuela and could lead to further reductions in oil production.
An Interview with Jeremy Gilbert, former Chief Petroleum Engineer at BP
(Note: Commentaries do not necessarily represent ASPO-USA's positions; they are personal statements and observations by informed commentators.)
Q: A recent series of posts at www.theoildrum.com attempt to divine the current status and future prospects of Saudi Arabia’s Ghawar field, the world’s largest. Your thoughts?
A: I am amazed at the energy and diligence which the authors exhibit in carrying out their analyses. It is tragic that the Saudis won't release more detailed performance data—and their own analyses—which would show the situation more clearly. It seems likely to me that the conclusion that Ghawar is in decline is correct. But it’s a big step to conclude that its decline will be steep. Oil companies employ reservoir engineers and reservoir geologists to deal with just the situation we have here: "a mature field is showing signs of declining production with its current development, what can we profitably do that might change this situation?"
Q. More than half the oil produced in Mexico is consumed in the U.S. In 2001, PEMEX built the world’s largest nitrogen injection plant to increase reservoir pressure at Cantarell. Production doubled to nearly 2 million barrels a day, but last year went into precipitous, apparently terminal decline. Would you, as a petroleum engineer, have anticipated this result?
A: I’m quite sure that the Mexicans were well aware of the uncertainty associated with gas flooding. There are many challenges associated with a successful gas flood. These center on being able to control the advance of the gas front. Because gas viscosity is so much less than that of the other reservoir fluids it will tend to cone and to finger through oil saturated zones, resulting in the premature breakthrough of injected gas into producing perforations. Once gas breakthrough occurs, oil production from the partially swept layer will decline very rapidly, and possibly completely.
Q. When do you expect global production to peak, and thereafter what do you expect the average decline rate to be?
A. I expect to see a peak sometime before 2015, but I don’t think we’ll see a simple maximum followed by a decline. I foresee a series of maxima, each followed by a brief decline. The simplest analogue would be a sine wave. It may be some time after the true peak before we can recognize it as such. Once one starts talking about average decline rates—for regions, countries, the world—one gets into a very murky place. Averaging is a dangerous process; averages hide all sorts of anomalies and variations. As we've seen the post-plateau decline rate for individual reservoirs can be as much as 15%/year. If we take the decline rate for a region, where fields are at different stages in their depletion and where some new reservoirs may be coming on stream then the decline rate is more likely to be 4-8%/year. The higher rates will be seen in area where exploration is effectively over, such as the U.K. Continental Shelf. Since the world as a whole is less mature than the North Sea, I expect a lower decline rate.
Q. You worked in Libya, Kuwait, and Abu Dhabi. How much scope is there for future discoveries in the Middle East?
A: There is still much scope for exploration in the Middle East, both in deeper horizons than those currently developed and in stratigraphically more complex areas. By their very nature these deep and complex reservoirs are likely to be smaller and more expensive to develop than the relatively shallow, relatively simple and generally large fields currently under production. For the last few decades there has been little incentive for these countries to 'mature' their exploration programs; they had access to so many discovered barrels that there was no point in going to look for more. In Kuwait and Bahrein, the smaller countries, the scope for additional oil to be discovered is fairly limited—and the deeper horizons are likely to be gas-prone—but in Saudi, in Iraq and to a lesser extent in Iran there could still be some pleasant surprises. This does not mean that a peak in these countries' production can be deferred—the delay from exploration to exploitation is too long—but it should mean that the post-plateau decline rate will be low, probably less than 5%/year. And it won't be 5% every year, there will be sharp variations.
Q. The U.S. is striving to keep Iran from enriching uranium. Having spent ten years working there, what is your view of these developments?
A: Nuclear weapons are another question, but I believe that Iran does have a clear need for nuclear electricity. Its population has doubled since the revolution. There are a huge number of young people who aspire to own cars, to improve their housing standards. Domestic demand for gasoline and for electricity is increasing sharply. It makes a lot of sense for Iran to conserve its oil resources for export and to use its own uranium resources in its own nuclear power stations to generate electricity. It’s not as though this is a totally new idea - nuclear power stations were close to being completed, by the USSR, near Ahwaz when I left in 1979—and that was at a time when Iran was producing 6 million barrels a day, and exporting close to 5. Since then, their oil production has fallen by one-third, and their exports by one-half.
Q. The European Union is becoming increasingly dependent on Russian oil and gas. Does this concern you?
A: I suspect that the Russians are getting into a real mess. It’s not that they lack the reserves to meet their contractual obligations, but they may not have the project management and technical skills to turn those reserves into production quickly, neither as quickly as the West would like nor as quickly as their economy is going to need.
Q. Peak oil forecasting seems to attract many amateurs, most of whom have never been on a drilling rig in their life. Where are the professionals?
A: I find it frustrating how few reservoir geologists or reservoir engineers have come out, post retirement, to speak in favor of the peak oil concept. In both Europe and the U.S. there are many people with suitable experience and it can’t be that they have not been exposed to the discussion, but for some reason they apparently don’t want to get involved. We don’t expect amateur aerodynamicists to second-guess Airbus and Boeing’s designs, so why do we assume that amateur industry-watchers can make worthwhile predictions of future oil supply?
Q. In listening to you, I get the sense that oil fields are somewhat more mysterious than we commonly believe. You seem to be saying that even with reams of data, there’s a lot hidden underground.
A: Well, what can I say! That's exactly what I keep trying to get across. A large reservoir like Prudhoe might have 50 or more reservoir engineers working on it full time. In addition, there'd be groups of reservoir geologists, of petrophysicists, of all sorts of other specialist engineers. They would use dozens of numerical models (some small and simple, others huge and requiring the most sophisticated software and hardware to use) to help them in their daily analysis of the field's behavior, to improve both short and long term performance forecasts, and to optimize future development plans. This is the reality, this is what I used to do, to manage, to direct. In short, every reservoir is different, they are almost 'alive'; they are mysterious things miles below us which we can never see or touch. Trying to understand them is a huge challenge; pretending that we can do so without access to the sophisticated tools and data which the industry uses, and even then has huge problems, is ridiculous.
In his 36 years with BP, Jeremy Gilbert worked in Kuwait, Abu Dhabi, Iran, Alaska, and the North Sea. In the late 1980s, Gilbert became BP’s Chief Petroleum Engineer, with responsibility for all of BP’s petroleum engineering worldwide. In this wide-ranging interview with ASPO-USA’s Randy Udall, he reflects on the myriad challenges we face in forecasting the future course of global oil production.