I attended the
American Geophysical Union meeting in San Francisco two weeks ago at which I heard a very interesting presentation by
David Hughes
of the Post Carbon Institute. He is more pessimistic about future
production potential from U.S. shale gas and tight oil formations than
some other analysts. Here I report some of the data on tight oil
production that led to his conclusion.
A number of analysts have issued optimistic assessments of the future
production potential of U.S. shale or tight oil. For example, the
International Energy Agency
recently predicted that the U.S. would be producing over 10 million
barrels per day of oil and natural gas liquids by 2020 before resuming a
gradual decline. Citigroup is even more optimistic.
Source: David Hughes, AGU presentation, December 2012.
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Source: David Hughes, AGU presentation, December 2012.
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David Hughes
has been studying detailed data on each individual well in shale gas
and tight oil formations in the United States as part of a study that
will be released by the Post Carbon Institute in February. The most
successful new oil-producing region is the Bakken in North Dakota and
Montana, which currently accounts for 42% of the U.S. tight oil total
and accounts for about 1/5 of the tight oil production that is projected
by Citigroup for 2022. Hughes finds that once output from a typical
Bakken well begins to decline, within 24 months its production flow is
down to 1/5 the level achieved at its peak. This is in line with
estimated decline rates separately published by the
North Dakota Department of Mineral Resources.
Source: David Hughes, AGU presentation, December 2012.
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Given the observed decline rates on existing wells, it is then a
straightforward mechanical exercise to ask the following question.
Suppose that no new wells were drilled after 2010. What would the path
of Bakken oil production then look like?
Source: David Hughes, AGU presentation, December 2012.
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Increasing the annual production thus requires not just new wells but
an increasing number of new wells each year; Hughes estimates that 820
new wells are needed just to offset Bakken field decline. But a second
feature in the data posing challenges for that plan is that while a few
wells in the Bakken have proven to be very productive, the average well
productivity is much lower. A limited number of lucrative sweet spots
account for much of the success so far.
Source: David Hughes, AGU presentation, December 2012.
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Source: David Hughes, AGU presentation, December 2012.
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Hughes argues that there are limits to the number of new wells that
will plausibly be drilled each year and the number of available well
locations. These factors make achieving the IEA or Citigroup objectives
difficult and mean a much more rapid decline in the production rate
after the peak is reached. For example, here are Hughes' calculations
if the current drilling rate were maintained-- 1500 new wells per year
leading to a tripling in the number of operating wells-- and if the
EIA's estimate of remaining productive locations is accepted. By
contrast, the Citigroup projection of a continuous plateau after
reaching peak production would require tens of thousands more well
locations than estimated to be available by the EIA.
Source: David Hughes, AGU presentation, December 2012.
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Oil produced from shale or tight formations is going to be very
helpful to the U.S. economy. But this is an expensive way to try to get
oil, and there may have been some overselling of how much these fields
are actually going to deliver.
Article Source:
Econbrowser