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Energy Risk: No More Blowouts, Dry Holes, or Abandoned Oil Wells

Abandoned Oil Well

According to the Alberta Ministry of Environment and Sustainable Resource Development, almost 400,000 oil and gas wells were drilled in the province during the period 1963 to 2012; for an average of about 8,000 per year.

Of those, 154,111 have been abandoned or about 38.5 percent.

The term ‘abandoned well’ means a well that is not in use because it ceased to produce or was dry to start with so it is hard to determine what percentage of Alberta’s abandoned wells were which.

A 1983 Oklahoma report  states however that almost one out of every three wells started in the state the previous year was dry and abandoned, which means 28 percent of the money spent for exploration was lost. It also states for “wildcats,” those exploratory wells drilled in unproven territory without direct evidence of the underlying strata, 70.5 percent of exploratory wildcats were dry holes.

A well can cost anywhere from a half million to a few billion dollars to drill.

North Dakota’s Department of Mineral Resources, recently put the average well completion costs for the Bakken at $9 million to $11 million — or about $3 million higher than the other hot U.S. oil development in Texas, the Eagle Ford.

In short, dry holes are expensive. In 1982 BP spent about $1.5 billion on its Mukluk well in the Beaufort Sea that came up empty.

Drilling wells can also be dangerous as witness the Deepwater Horizon incident, the Kuwait oil fires and the blowout currently burning in the Gulf of Mexico.

Abandoned wells also cause environmental damage due to leaks and though the percentage of wells that do leak is debated, even Schlumberger, in a 2003 article states that, “Since the earliest gas wells, uncontrolled migration of hydrocarbons to the surface has challenged the oil and gas industry.”

Of Alberta’s 154,111 abandoned wells 52,831 or 34 percent remain unreclaimed, meaning the land around those wells is unusable for any other purpose. 

By comparisons, Gerard Nihous of the University of Hawaii estimates the number of 100 MW OTEC power plants the oceans are capable of supporting is half a million.

Effectively these would be a half million hydrogen wells capable of providing 5 times the energy of the world’s producing oil wells or 8 times the output of its producing natural gas wells.

Not one of these wells would ever be a dry hole or would ever need to be abandoned.

In the case of a catastrophic failure they would immediately cease to produce fuel to feed a fire.

The worst that could happen would be some or all of the aquatic life that thrived in the first place in the vicinity of the plant due to the convective upwelling of nutrients induced by the movement of surface heat to the depths, would be destroyed.

Aquatic life would continue to thrive around the other operating plants and would soon return to the vicinity of the new plant that replaced the one destroyed.

The kicker though would be each operating hydrogen well would be helping to mitigate the problems of atmospheric carbon, sea level rise and storm surge rather than exacerbating those threats as do the 13,788 wells per year (the past 10 year average) being drilled in Alberta and the many thousands of others being drilled elsewhere. 

Photo Credit: Abandoned Well/shutterstock

Jim Baird's picture

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Geoffrey Styles's picture
Geoffrey Styles on August 1, 2013

Jim,

Glad to see you blogging after reading many well-informed comments from you in the past.  You’ve raised an interesting subject that doesn’t get discussed much. I thought it might be helpful to shed a little light on the dry holes vs. other abandoned wells.

In the decades before 3D seismic and other modern exploration techniques, the rate of successful exploratory wells vs. dry holes was often no better than 1 in 9 in areas without previous resource discovery. Once oil or gas was discovered, the rate for subsequent producing wells would be much better. In any case, most of those wells cost a lot less than current wells, even after inflation, because drilling depths have generally increased and the whole process has become much more sophisticated and hardware-intensive. 

Mukluk was an unusual case, because in the 1980s drilling that exploratory well required building an artificial island and other infrastructure in pretty extreme conditions.  It’s a fascinating story about a mistake that likely woudn’t have happened today. Technology has drastrically reduced the risk of dry holes.

Wells in places like the Bakken, Eagle Ford, Marcellus and other shales are less prone to this concern, since these are “resource plays”.  That is, the resource has already been identified, in many cases long ago, and the risk of an entirely dry hole is very low, and the risk of a well that ends up being non-commercial is also much lower than in many other formations. Your $10 million Bakken well is likely to yield around $30 million over its life at current oil prices and discounts vs. WTI.  How does an OTEC “hydrogen well” compare?

Geoffrey Styles's picture
Geoffrey Styles on August 2, 2013

Jim,

The analogy that seems closer is to geothermal, which also taps delta-T (though typically much bigger, and thus at higher efficiency) and also produces steady power which could be used to make electrolytic H2 if desired.

The big edge that oil investments like the Bakken have is that they produce hydrocarbon liquids that are 100% compatible with the existing vehicle fleet. (The effective electricity price of US gasoline is on the order of $0.40/kWh.)They also tend to pay out quickly, i.e. the production is front-loaded rather than ratable over many years. If your investment model is based on NPV, that is another advantage. 

Still, I don’t see any reason OTEC shouldn’t get the same chance at being part of the future energy mix as other ocean-based technologies.  It has always seemed a lot more practical to me than wave and tidal power.  The Lockheed project should get a lot of attention.

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