Another flaw in the human character is that everybody wants to build and nobody wants to do maintenance
—Kurt Vonnegut

Last week we took a look at new oil production outside of OPEC. I found that phased start-ups are not being postponed despite a deteriorating economic situation that has resulted in low prices, large OPEC cuts and an oil glut on the world market. I concluded that this strategy is shortsighted and self-defeating, especially if the global recession is deeper and longer than the Fed and the Treasury Department anticipate. I view a destructive period of deflation as likely.

New oil was the term PN for conventional oil in equation 1 below.

  1. S(t) = PE(t)(1 – DI) + PN(t) + PSC(t) where S = available supply over the time interval t (a year), PE = the existing production base, PN = new production, PSC = spare capacity and DI = the net decline rate

In a significant update to last week’s column, secretary general Abdalla el-Badri announced OPEC project delays without being specific about what they were. El-Badri is still hoping the large non-OPEC exporters will cut production to help boost the shaky oil price.

“We urge Norway, Russia and Mexico to give a hand, because the situation is very difficult and we cannot handle it by ourselves,” he said…

El-Badri expressed concern about the impact of the lower prices on the oil investment plans of OPEC producing countries, disclosing that 35 of 150 planned upstream projects had been postponed beyond 2013. He said OPEC plans had called for 5 million b/d of new crude output capacity to be added by 2012, but that the timing of this capacity addition would now be “stretched” because of the precipitous fall in oil prices over the past few months.”(We are) postponing 35 projects to after 2013 from our 150 planned,” he said. “Of our firm projects to 2012, some will be delayed,” he said.

I’ll bet that most of the delayed projects are maintenance upgrades, not new oil field developments, as I discuss below. Today I examine threats to new unconventional oil production and the effects on declines in the existing production base (i.e. the term PE(t)(1 – DI)).

Trouble at the Tar Sands

The first domino to fall when the global economy went south was tar sands unconventional oil production. Suncor, Petro-Canada and other major players have scaled investment way back. A Merrill Lynch analysis indicates that new tar sands oil is competitive at $80/barrel. Existing oil production is said to lose money at $32, so operators are getting close to the edge should prices fall $4/barrel below today’s price. The Canadian Energy Research Institute (CERI) has just issued a report which estimates $70 (US) as the price at which new tar sands oil becomes viable.

Figure 1 shows CERI’s production scenarios based on future economic conditions. The National Post (February 5, 2009) summarized the hit on investment detailed in the CERI report.

The global credit crunch and collapse of oil prices have cancelled the Alberta oil sands boom, resulting in a loss in investment of $97-billion to $241-billion in the next decade that will be felt throughout the Canadian economy, the Canadian Energy Research Institute said in a report Thursday.

While the Alberta deposits will still attract $218-billion in spending to develop new oil production in the next 11 years, the pace of development will be much slower than was expected only three months ago, the independent research firm said.

Figure 1 — CERI production scenarios under various economic projections. The probable production range is shown in gray. The green line is the worst case.

I concluded that production growth at the tar sands was slowing down long before the current economic crisis (Energy Bulletin, January 2, 2008). The reference case (red line in Figure 1) is very improbable, especially the fast growth out to 2016. The “unconstrained” case (blue line) resides in the realm of pure fantasy. It is easy to see that in the worst economic case, which I consider likely, lost production will be in the range of 1 million barrels-per-day by 2015. This large number speaks for itself.

Perhaps there’s an upside to this supply-side disaster. If climate is our chief concern, and problems with the oil supply can be postponed for a decade or longer, as Interior Secretary Ken Salazar and Energy Secretary Steven Chu seem to believe, the loss of tar sands oil could be viewed as a blessing, not a curse. In fact, why not take the initiative? Why doesn’t the U.S. simply prohibit imports of dirty carbon-intensive tar sands oil altogether? Canada could do its part by phasing out oil sands production, which would enable them to meet their carbon emissions limits under the Kyoto Protocol.

If Chu and Salazar are right, and I am wrong to characterize the probable loss of 1 million barrels-per-day as a disaster, it looks like a win-win! Unfortunately an unblinkered view of the loss tells a different story. Canada is the largest exporter of oil to the United States. Our future refining plans depend on a continuing and growing supply of tar sands oil. Losing that much production will cause major economic headaches in the U.S. unless we prepare for it in advance.

Peak oil and climate change agendas do not always coincide. If the world were swimming in conventional oil as it seemed during the Golden Age in the decades just after World War II, we would not need synthetic crude from the tar sands.

Lack of Investment and Decline Rates

A substantial part of oil company upstream investment goes toward field upgrades and maintenance.  This spending is necessary to maintain output or slow declines at post-peak oil fields. Such fields are studied in the IEA’s World Energy Outlook 2008. Post-peak fields make up a hefty slice of world oil production. Based on an analysis of the IHS database, the IEA’s report describes just how large this slice is—

Of a total of 798 producing fields in our field-by-field database, we prepared a dataset of 651 fields with initial reserves of at least 50 million barrels in order to carry out our analysis of decline rates. Of this set, 580 fields were found to have passed peak production. In other words, for each of these fields, production over the latest year of production is below the maximum level ever achieved in any one year. These fields produced a total of 40.5 million b/d (barrels-per-day) in 2007, or 58% of the world crude oil production.

Based on raw production data, the IEA figured the decline rate at 5.1% per year. Generalizing their result by including fields with less than 50 million barrels in initial recoverable reserves, the IEA estimated the overall decline rate in all post-peak fields to be 6.7%—smaller fields decline faster. If no investment were put into maintaining and upgrading these fields, the IEA estimated that the “natural” decline rate is 9%. Thus for all post-peak oil fields, the term DI in PE(t)(1 – DI) from equation (1) lies somewhere between 6.7% and 9% depending on the level of investment.

I prepared an abstract scenario (Figure 2) to give you an idea of how investment levels might affect overall declines in post-peak fields.

Figure 2 — An investment scenario for post-peak fields. The initial period of 6.7% decline is replaced by a middle period of 8% decline based on lack of investment in an economic downturn (red line). An economic upturn lifts demand and prices, and thus reinvigorates investment. Declines are maintained at 6.7% once again.

Notice first that the effects of the exponential decrease overwhelm the relatively small impact of an investment shortfall that raises the decline rate closer to the “natural” rate. Lost production due to lack of investment (the difference between the blue and red lines) amounts to only 2.77% of the total production over time.

Nevertheless, if the decline rate were allowed to rise to 8% for an extended period as shown in Figure 2, the loss over the entire period (not the difference at the end) would come to 1.12 million barrels per day (2.77% of the IEA’s 40.5 million b/d). Although this shortfall would be spread across several years in the scenario, it is not a trivial amount of lost production given that the annual production lost from post-peak fields alone is 2.71 million barrels-per-day (40.5 million * .067) after full investment. The additional production shortfall from lack of maintenance must also be replaced by new oil each year. Every drop counts.

There is a lot of evidence that maintenance and upgrades are suffering during the current downturn. Oil service companies are getting hit hard. Schlumberger forecasts hard times ahead in the Houston Chronicle (January, 23, 2009)—

Schlumberger delivered still more bad news Friday about the weakening state of the global oil and gas industry, reporting lower fourth quarter profits, additional layoffs and a glum forecast for the rest of 2009…

Earlier this month, Schlumberger said it would cut up to 1,000 of its 19,000 North American employees, including up to 100 of its 5,000 jobs in the Houston area. But for the first time Friday, the company said it will cut 5,000 jobs worldwide, or almost 6 percent of its 84,000-strong work force…

Schlumberger also offered a downcast view of the coming year. “We expect 2009 activity to weaken across the board with the most significant declines occurring in North American gas drilling, Russian oil production enhancement and in mature offshore basins,” [CEO Andrew] Gould said in a statement. With oil and gas prices so low, many emerging resource plays, like heavy oil projects in Canada, also will not be economic, he said. [emphasis added]

Gould’s remarks about Russia should give us pause. Last year’s production fell 0.7% compared to 2007 and January came in 0.9% below the same month last year. I’ve got a bad feeling about this. As for mature offshore basins, Shell has announced some delays.

The company postponed investment decisions on upgrading its deepwater Mars platform in the Gulf of Mexico and developing the Pierce field in the U.K.’s North Sea as it waits for industry costs to decline.

Rig counts are also down. The latest Baker Hughes data indicates that—

The number of rotary rigs drilling for oil is down 26 at 283. The number of rigs targeting oil is 41 less than last year’s level of activity. Rigs currently drilling for oil represent 21.0% percent of total drilling activity. [Note – the large majority of rigs in service are drilling for natural gas, not oil]

We are closer to the beginning of the economic downturn than we are to its end. Inactivity at oil services companies or falling rig counts should be regarded as preliminary indicators, not the end of the story. The scenario shown in Figure 2 clearly shows that money put toward maintenance of post-peak fields would be far better spent on new oil projects if investment is constrained by deteriorating economic conditions and low oil prices, especially for the larger oil companies (IOCs or NOCs). Therefore it is far more profitable for TNK-BP to put the Verkhnechonsk field in Eastern Siberia on-stream than it is for them to maintain output in their aging Western Siberian fields. Unfortunately this new oil may help drive down prices and maintenance will suffer at the same time as investment diminishes.

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