The Peak Oil Crisis: Deep in the Heart of Texas

December 12, 2012 2:00 PM2 comments

The Association for the Study of Peak Oil recently held its annual conference down in Austin, Texas. The venue for the meeting was right across the street from the University of Texas football stadium which is as close to the heart of Texas as you can get. This year the conference focused on two main themes – the rapid growth of tight oil production in the U.S. and where it is going; and the economics of oil – or will prices continue to allow us to grow our economy.

The conference opened, however, with two presentations expressing concerns about the practice of lumping together various forms of liquid hydrocarbons and calling it oil in official statistics – when several of the liquids being lumped in do not have the same energy value nor the utility of oil as a transportation fuel. Ethanol, now ubiquitous in our gasoline, contains some 25 percent less energy than regular gasoline and gives much less mileage. Natural Gas Plant liquids are useful mainly as a feedstock for petrochemicals and propane heating, but are of only marginal use in transportation fuels. Adding refinery processing gains as a source of energy is disingenuous as the refining simply breaks down the oil in smaller molecules which take up more volume and hence give the impression that we have more “oil” products after refining. The truth is the energy remains the same before and after refining and we have simply “inflated” the liquids so they take up more barrels.

All this would be academic, except that this practice, while it may make us feel better about increasing “oil” production, will come back to bite us in the form of less and higher-priced transportation fuels — the existence of which is illusory.

In recent months the growing supply of “tight” oil in the U.S. produced by fracking has sent numerous organizations and publications into frenzies of exuberance as they described the good economic times that are about to come from so much domestically produced oil. This week the U.S. Department of Energy and even the U.S. Intelligence Community joined in with optimistic forecasts. A National Intelligence Council advisory group issued a report talking about a “tectonic shift” that could have the U.S. producing some 15 million barrels of oil per day and becoming a major energy exporter by 2020. This will cut oil prices, increase economic growth, and add millions of jobs.

Although the U.S. Energy Information Administration is not quite as enthusiastic as the intelligence folks, its latest forecast sees U.S. oil production increasing by 234,000 barrels a day (b/d) each year until 2019 when U.S. oil production reaches 7.5 million b/d before leveling off and then declining gradually for another 20 years to 6 million b/d by 2040. All is fine for the next 30 years. Even when production starts to decline, we really shouldn’t worry because by then our cars will be so efficient that we can get along with much less gasoline.

The EIA’s new forecast for natural gas is similar, except production continues to grow merrily off into the distant future capturing an ever-increasing share of our electricity generation, fueling our heavy-duty trucks, and even leaving some over for export to less fortunate nations.

At the Texas conference, opposing views as to the validity of these forecasts were presented. Two speakers forecast that U.S. tight oil production would increase from essentially zero in 2005 to 4 or 4.5 million b/d by 2020 and would remain there to 2030 or beyond. It is not clear if these optimistic forecasts have really examined the extraordinarily fast decline rates of fracked wells.

Our third speaker, one of several who have actually studied the depletion rates of fracked wells, clearly has a problem with all this euphoria. There are now about 5,000 wells in North Dakota, one of the two major tight oil production “plays” that are pumping out an average of 143 b/d for each well or some 700,000 per day. Our speaker’s well-by-well study of the first 2500 wells in the Bakken discussed at the conference, however, concluded that this production would drop by 38 percent within a year unless more wells were drilled. At these depletion rates, it will take 1,600 new wells per year just to stay even. In the most recent 12 months of drilling available some 1750 new wells came into production in the Bakken – leaving very few to increase production.

If we assume that the decline characteristics are similar in other tight oil formations, then if production were ever to reach 3 million b/d, well over 1 million b/d of production would have to be replaced through new well drilling each year to maintain production. For this reason, the skeptical presenter at the Texas conference estimates that tight oil production in the U.S. will only reach 1-2 million b/d by 2020 – depending on price – as compared to the 4 million b/d forecast by the optimistic presenters.

We should know which of these widely divergent forecasts will be closer to reality in the coming year. If production at the Bakken and Eagle Ford shales keep increasing rapidly over the next 12-24 months then perhaps 3 million b/d of oil production or more is possible. However, if the spectacular rate of increase we have seen in the last few years starts to slow, then a peak of tight oil production in the 1-2 million b/d range seems more likely.

Another question that bears on the question of how much tight oil will be available in coming years is just how much a tight oil well costs to drill and how much oil can be recovered from each. Here the estimates are widely divergent with the pessimists talking about costs in excess of $10 million per well and breakeven costs in the area of $85 a barrel. The optimists say it costs $6 – 7 million to drill and frack a tight oil well and that breakeven costs are in the area of $40-50 a barrel. If these numbers are true, then drillers should be making lots of money; if, however, the marginal breakeven cost is close to what tight oil can be sold for, then drilling should start slowing soon.





  • EIA reports crude oil field production and crude oil field production with lease condensate (the liquids that separate at the well head). Natural gas liquids which are separated from natural gas in the first refining step are reported as a sub heading under Other Liquids. Its a red herring to suggest that EIA is reporting natural gas liquids as crude oil.

    The first horizontal hydraulically fractured well in ND was drilled in 2005 and developed in 2006. It was drilled next to a previously drilled dry hole. Since that time, the number of wells drilled per year has increased exponentially. Improvement in all other measures of productivity have at least been linear with increased learning experience drilling the wells. In a time of exponential growth, you need to examine the increase in production for the month divided by the number of wells brought on line during that same period. With that analysis, new wells are producing at a rate closer to 500 barrels per day. Similarly, you would never analyze the first half of the wells drilled unless it were to show the huge change in numbers when you compare those numbers to the productivity of the second half of the wells drilled. Yes the decay rate is high. But if you pay for a well in the first year of production and then make pure profit for the next 3 to 5 years, the investment perspective changes.

    Final point, the formations change with geography. The shale formations below the major oil reservoirs in Texas appear to be more easily fractured and yield a higher initial production rate. They are a lot closer to existing infrastructure which has been increased to the tune of 900,000 bpd over the last couple of years. The increase capacity has not been sufficient to keep up with the increased production as TX has gone from less than 1.1 million barrels a day to just over 2.0 million bpd in Sept 2012.

    The bottom line is that there has been a growth in the instantaneous product rate in ND of 0.6 million bpd. Similarly there has been a growth in instantaneous product in TX of 0.9 million bpd for a combined 1.5 million bpd. It would not surprise me at all if the total had increased to 2.0 million bpd when the year end numbers are reported in March next year.

  • Further evidence of significant declines in oil production lies in the quarterly 10K and annual reports of all the oil majors. ExxonMobil, Shell, and Chevron, to name a few majors, are all reporting real declines in core oil production. Oil projects throughout the world for the majors now take on extreme risk in and in extreme locations. Cracking open shale formations and cooking tar sands using massive amounts of water along with armies of men and heavy equipment represents solid evidence the low hanging “oil fruit” is now gone. Energy reality will continue to drive this point home and tear to shreds all the nonsense, magical and feel good thinking which is so much a part of the American scene today.

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