Old Oil Fields Are A Major Source Of New Supply

CANAKKALE, TURKEY - FEBRUARY 16: Bahamian flagged 66-meter-long and 88-meter-high oil platform 'Deborah' passes through Dardanelles, in Canakkale, Turkey on February 16, 2018. (Photo by Burak Akay/Anadolu Agency/Getty Images)

The animated show South Park ran an episode in which Professor Chaos becomes frustrated trying to come up with an idea for mischief that hasn’t already been done by The Simpsons.  “Simpons did it,” is the response to his every suggestion.  In petroleum economics, the place of the Simpsons is filled by (my mentor) the late Morry Adelman, who wrote a number of papers on the basics which have stood the test of time, even if few are aware of them.  (How many read “Resources and Energy?”)

I was reminded of this by Javier Blas’ article “Aging Oil Fields Defy Gravity to Pump More Crude,” in which BP CEO Bob Dudley talks that “I cannot remember ever in my career having seen a negative decline rate.”  The funny thing is that only four days earlier, Rystad Energy reported that they estimated growth in reserves in old fields of 151 billion barrels over the previous four years.  (And no, two thirds were in conventional fields, not shale.)

Indeed, many would be incredulous to hear that oil reserves were not declining, given headlines like “Global oil supply to lag demand after 2020 unless new investments are approved soon."  Although a careful reading suggests that this is nearly always true, just as a car won't move if you don't hit the gas.

Morry Adelman repeatedly tried to explain that oil reserves are an inventory, draw down by sales (production) and replaced by investment (exploration and development).  He also demonstrated that most companies have a choice between more intensive development of existing fields or exploring for and developing new fields, and that the cost of the two endeavors should thus generally be equal.  (Very simplified.)

But the point is often overlooked by those who cry alarm at news that ‘discoveries’ are at historic lows, thinking that new supply only comes from new fields.  This reflects in part the fact that drilling a few wells in an existing field, adding gas injection, or doing new seismic to identify missed oil in a reservoir is often so small scale that it doesn’t make the news—especially compared to billion dollar oil fields in deepwater or Arctic environments.

This can easily be seen in data on U.S. oil reserves, as in the figure below.  Most oil reserves added every year are due to revisions and extension, not discoveries.  While the proportion is higher in the U.S. than some other countries, which do not use the more conservative “proved reserves” estimate, the phenomenon is global.

U.S. Reserve Additions (mln bbls)Data from EIA.

In a 1997 article in the Oil & Gas Journal, by Adelman and myself, we discussed the many ways reserves are increased by changes in technology, investment and infrastructure, noting, for example, that significant amounts of oil in the British North Sea came from fields that were not immediately developed, but which became economic as the growing pipeline infrastructure made it cheaper to connect a small field, and the use of subsea templates enabled developers to avoid using an expensive platform.

Observers were often misled by peak oil writers, who argued that the idea of increasing recovery from older fields was a chimera.  Jean Laherrere, co-author of the infamous March 1998 Scientific American article “The End of Cheap Oil,” made this explicit denial of increased recovery:  “Business as usual is for economists but production engineers do not care for BAU because the recovery factor depends mainly upon the geology of the reservoir. Technology cannot change the geology of the reservoir, but technology (in particular horizontal drilling) can help to produce faster, but no more…”

Partly, this reflected a general bias towards ultra-pessimism on the part of some peak oil theorists, like Laherrere, but also the fact that the mathematical methods he used to estimate field, national or regional resources required the assumption that field sizes not increase over time.  Which explains why the work has been so much in error.

A secondary problem stems from the impact of prices on additional recovery.  When prices collapse, it is far easier to postpone small-scale investments in enhanced recovery than abandoning a multi-year megaproject.  This can lead to poor estimates of field decline rates which don’t take oil prices and investment in to account.  And many forecasts have proved too pessimistic because the forecasters don’t include the role of more intensive development of existing fields.  (I actually demonstrated this quantitatively in a 1990 paper, “An Omitted Variable in OECD Supply Forecasting," delivered to the 12th Annual North American Conference, International Association of Energy Economics, Ottawa Canada.”)

For most of the past four decades, oil supply forecasts (non-OPEC, that is) have tended to be too pessimistic and a major reason is the difficulty of analyzing new reserve additions and incremental production from existing fields.  The activity is relatively small-scale, meaning it doesn’t make most analysts radar scopes, and the data ranges from limited to non-existent.  But given that the average recovery factor globally is less than 40%, there are easily hundreds of billions of barrels that can be accessed with better technology and more investment.  In the short term, the error is not very large, but longer-term, it adds up and is a major factor behind the perceived scarcity that has dominated the expectations of so many.
