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Back to Bakken

September 8, 2014

Many of our readers dislike reading negative words about Bakken. Yes, it’s still being drilled and currently is producing 1.1 million bbls per day.1 But what does it take to keep up that production level?

Production levels in “tight oil” formations, including the Bakken, start high but drop very quickly: on average Bakken wells have a 69 percent decline rate in the first year of production, but over a 5-year period the decline rate is 94 percent. This is why production from Bakken wells that were drilled before 2011 reached a maximum (peak) of about 350,000 bbls per day in 2011, and then dropped steeply to less than 200,000 bbls per day by mid-2012.

To maintain Bakken production, some experts estimate that 40 percent of wells must be replaced annually.2 One estimate of the annual cost to offset that decline is about $8.2 billion. Energy experts also estimate that more than 6,000 wells must be drilled per year in all tight U.S. formations to maintain such high production levels. Estimates of the cost for drilling 6,000 wells annually start at $35 billion.Funding that level of effort requires continually stimulating investment income, so of course the industry wants to see only happy talk about Bakken’s current and future production.

We can oblige that wish in the short term, because some credible energy analysts estimate that at the highest rate of well replacement, tight oil production at the major plays: Bakken in North Dakota and adjacent states, and Eagle Ford in Texas, will eventually peak at a total production of around 2.3 million bbls/day by 2017.

The peak will come earlier (2015) if 2000 replacement wells are drilled per year, and later (2017) if 1,500 are added per year. At the peak, all useful drilling sites likely will have been fully exploited3 and then production will drop. The expectation is that production will be back to 2012 levels by 2019, and will keep on dropping to stripper well status (production of less than 10 bbls per day), by 2025.

Blue curve - Lower 48 U.S.

Blue curve – Lower 48 U.S.

This prediction contrasts starkly with the history of U.S. conventional oil production, shown in the graph, above. Production in the lower 48 states grew exponentially from the 1950s to the 1970 peak, then went into steep decline. Alaskan oil production leveled it off until 1989, when production again dropped steeply. In 2008 tight oil production turned the U.S. oil production curve upward once again, but that trend is expected to peak by about 2019 — depending on how the economy progresses.

The tight oil peak is likely to be a very sharp one, with a decline curve nearly as steep as the rising one.

In our current global economic system, dating only from the end of WW II, finance and energy are tightly intertwined. Finance/energy analysts now warn that prices for oil and derivatives are low compared to the costs of production and distribution. This negative cash flow has continued for a number of years, even as interest rates for financing new wells went zooming down. Also—in spite of what you thought you knew—interest rates could turn negative. Add increasing turmoil in the oil-rich Middle Eastern countries, and we soon could be facing worldwide financial turmoil.4

IF the tight oil estimates quoted above prove correct, and IF the complexly contorted Monterey Formation in California remains difficult or impossible to frack,5 U.S. oil production would not help address the world’s petroleum demand.


  1. Tight oil production figures summarized in J.D. Hughes, Drill, Baby, Drill, Post-Carbon Institute, February 2013,
  1. Rune Likvern, Is the Typical NDIC Bakken Tight Oil Well a Sales Pitch?, The Oil Drum, April 29, 2013:
  1. For a detailed explanation of current financial trends and their relation to energy production and distribution, see the 12-minute talk, “Global Financial System: On Life Support.” by Roger Boyd, August 14, 2014 Speaker bio at
  1. J. D. Hughes, Drilling California: A Reality Check on the Monterey Shale, Post Carbon Institute, 2013:


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