Helping America Understand and Adapt to a New Energy Reality

A Look Back at North Sea Oil Production Projections

By on April 18, 2011 in Commentary

(Note: Commentaries do not necessarily represent the ASPO-USA position.)

In 1999, I wrote a paper concerning the production decline of North Sea oil fields and made projections for the future of Norwegian and United Kingdom (U.K.) oil production (crude + condensate). For comparison purposes, I compared my projections with those by the U.S. Department of Energy/Energy Information Administration (US DOE/EIA). Table I is from that paper.

Author and U.S. DOE/EIA

Projections of Norwegian and U.K. Oil Production to 2020

Table I

a Excludes NGL’s and processor gain. From 1995 through 1998 crude + condensate made up 90% of U.K.’s total oil production and 96% of Norway’s total liquid hydrocarbons production. It’s assumed that these percentages won’t change in the future.

Figures 1 and 2 are graphs of historic (through 1998) and projected (after 1998) production for Norway and the U.K. based upon my projections.

    Figure I Historic and author’s projected oil production for Norway
    Figure 2 Historic and author’s projected oil production for the U.K.

Figures 3 and 4 are graphs of historic (through 1998) and projected (after 1998) production for Norway and the U.K. based upon projections by the US DOE/EIA.

    Figure 3 Historic projected oil production for Norway by the US DOE/EIA
    Figure 4 Historic projected oil production for the U.K. by the US DOE/EIA

How did the US DOE/EIA and I do in our projections of Norwegian and U.K. oil production for 2010? Table II shows the comparison.

Author and U.S. DOE/EIA

Projections of Norwegian and U.K. Oil Production for 2010

Table II

a The 2010 values for the US DOE/EIA is based upon an interpolation between the peak projected values and the 2020 projected values

b Based upon data from the US DOE/EIA

Why did the US DOE/EIA do such a poor job at projecting future Norwegian and U.K. oil production?

It’s obvious that it did not base its projections on actual field production data. It appears that its objective was to be optimistic rather than realistic.

By the late 1990s it was clear that most of the large (+50,000 b/d) oil fields in both Norway and the U.K. that had been in production for more than 4 years were in decline with decline rates of typically 10%/year or higher. There were also a limited number of large fields scheduled to come on-line after 1999 in both countries that could negate the rapid decline of the older fields. It should have been obvious that the peak production years wouldn’t occur as late as, and that the decline rates would be higher than, the US DOE/EIA was projecting.

The poor performance of the US DOE/EIA in Norway and the U.K. suggests that its projections for other regions, as well as globally, should be viewed with a high degree of skepticism.

An example of the optimism that still permeates the US DOE/EIA is exemplified in its Annual Energy Outlook 2010 (AEO2010). The AEO2010 projects that Lower 48-Offshore oil production will increase from 1.67 mb/d in 2010 to 2.36 mb/d in 2035. For the projection in 2035 to be valid, the deepwater Gulf of Mexico (GOM) would have to produce at least 1.4 mb/d in 2035. I see no possibility that the deepwater GOM will produce anything remotely close to 1.4 mb/d in 2035.

Even prior to the restrictions placed on U.S. offshore oil exploration due to the Deepwater Horizon explosion, I was making the case that deepwater GOM oil production would peak around 2010 (see Drill baby drill-a reality check) and I stand by that prediction.

Seven +50,000 b/d fields were brought on-line in the deepwater GOM during 2007-2010 with a summed peak projected production of ~900,000 b/d. That led to a substantial increase in deepwater production for 2009 and 2010. Just as in the case of North Sea oil production, there are a limited number of large fields to bring on-line in a timely manner to negate the decline of the older deepwater fields. Only 2 significant fields are expected to come on-line during 2011-2013 with a summed peak projected production of 90,000 b/d.

If, as I expect, yearly deepwater GOM oil production starts declining in the near future*, I expect to hear that the decline was due to drilling restrictions. That sounds good but production over the next 4-5 years will depend on production projects that had started by the time of the Deepwater Horizon explosion, not on wildcat drilling.

The media, public, and politicians like the optimistic projections by the US DOE/EIA, US Geological Survey** (on-shore), and Minerals Management Service (off-shore), but that optimism doesn’t mean their projections and assessments are accurate.

*Looking at 6-month increments for total GOM oil production, production reached its highest level in the second half of 2009 at 1.73 mb/d. In the first half of 2010 it was down to 1.63 mb/d and for the first 4 months of the second half it was down to 1.59 mb/d suggesting that deepwater GOM production may have peaked although yearly production in 2010 should be higher than in 2009.

**In 2010 the USGS had to downgrade its assessed volume of technically recoverable oil in the National Petroleum Reserve-Alaska to about 1/10 of its previous estimate

Roger Blanchard teaches chemistry at Lake Superior State University and authored the book, The Future of Global Oil Production: Facts, Figures, Trends and Projections by Region, McFarland & Company, 2005. He also grows fruit trees and hay on acreage outside Sault Ste. Marie, Mich.

Subscribe

If you enjoyed this article, subscribe now to receive more just like it.

  • Pingback: Scotland’s peak oil plan (or lack thereof) | failing gracefully

  • cameron conacher

    If DOE was considering OIP (oil in place) and technology rescueing us then their graphs make sense (many years out). Otherwise if technology is stagnant only typically 30% of OIP is extractable, and perhaps less (no nitrogen, CO2 injection a hundred miles offshore due to economical costs, access to sour oil) oil can be obtained. Price stability (even abetted by speculators) permits more oil extraction (new infrastructure) with higher cost technologies if 2-5 years is maintained for investers to get back proceeds. The only way to ensure that level of income transfer (consumer to producer) is to print money as recession would result with any non inflationary dollar transfers and so we have Federal Reserve QE2. QE2 comes at a cost: inflation. The other option; no oil for commerce (with USA at 70% consumer economy) is a a worse alternative.

  • Bill Simpson near Slidell LA.

    Scary, but excellent work, professor. I guess we are building the world’s largest embassy complex in Iraq for a reason.

Top