Frozen oil valves in Prudhoe Bay, Alaska
Frozen valves at Prudhoe Bay in Alaska. According to the author, oil production peaked in the late 1980s and has steadily fallen by 10 percent annually since then. The estimated ultimate recovery (EUR) is now projected at just over 12 billion barrels of oil.

Will Technology Delay Peak Oil?

Advanced production techniques have accelerated oil recovery... and decline rates

By Roger Blanchard

Reprinted from the ASPO USA news letter

It's not unusual to hear from economists that modern oil production technology significantly increases the amount of oil that can be extracted from oil fields. How valid is that belief? A quick look at the production histories of five giant oil fields raises serious doubts.

There are several problems with assessing technology's role. The first problem is establishing an initial value for an oilfield's estimated ultimate recovery (EUR). A second problem is that initial EUR values for discoveries made over the last several decades can have uncertainties of 10% or more and fields discovered prior to that can have uncertainties of 20% or more. It would be more appropriate to ask: does modern technology increase a field's EUR beyond the upper limit of uncertainty for the field's initial EUR value? Accurate EUR values are best determined after a field starts declining. Plotting annual production versus cumulative production and extrapolating a best-fit line through the declining data point values to the x-axis provides accurate EUR values. A third problem is that the oil industry commonly underreports initial EUR values, per SEC regulations, so that the field appears to "grow" over time.

In the Prudhoe Bay field's early days, oil industry said the field would ultimately produce ~10 billion barrels (Gb) of oil. Jeremy Gilbert, former BP Chief Petroleum Engineer, has stated that the field's producers had aninternal estimate of ~12-15 Gb. The lower end of that estimate is now supported by production data since the field started declining in the late 1980s (see Fig. 1).

Fig. 1 : Prudhoe Bay Production history

Extrapolation of the best-fit line through the declining data points gives an ultimate recovery of ~12.3 Gb. From 1989 through 2003, the Prudhoe Bay field declined at an average rate of 10.1%/year. In this case, advanced extraction technology has not significantly altered the initial EUR value. The same situation is also observed for North Sea fields. Oil producers working in the North Sea have used the best available technology. Those technologies have led to very high production rates in the early stages of production and ultimately high decline rates. Table 1 illustrates that point.


On-line Date Peak Year Max. Prod. (b/d) 2001 Prod. (b/d) 2002 Prod. (b/d)

Absolute Decline (b/d)

% Abs. Decline 2001-2002 % Change








76.3 -12.4








70.0 -12.5








65.3 -7.8

Table 1 The Statfjord (EUR ~4.5Gb), Gullfaks (EUR ~2.8Gb) and Oseberg (EUR ~2.8Gb) fields are the largest fields in the Norwegian sector of the North Sea. Their decline rates from peak production through 2003 are 12.1%/year, 13.8%/year and 11.9%/year, respectively. Their production rates through the first 11 months of 2005 were ~96,000 b/d, ~144,000 b/d and ~148,000 b/d, illustrating that the fields continue to decline. The Norwegian Petroleum Directorate (NPD) annually updates EUR values for Norwegian fields.

EUR values for some fields increase with time, some decrease. The summed EUR value has increased somewhat with time but the increase has not been sufficient to suggest that modern technology has significantly altered initial EUR values. In recent years, both Norway and the United Kingdom (UK) dramatically increased the number of producing fields by bringing on line much smaller fields compared to the large early fields. That has not prevented rapid production declines. For the UK, the production rate has declined by 38%, from 2.68 mb/d in 1999 to 1.66 mb/d during the first 10 months of 2005 (U.S. DOE/EIA data). Norway's production rate has declined 15%, from 3.20 mb/d in 2000 to 2.71 mb/d in 2005 (U.S. DOE/EIA data).

Mexico's Cantarell complex is in the early stage of decline. Jean Laherrere estimates the ultimate recovery for the Cantarell complex to be ~19 Gb. According to a 2002 Simmons & Co. Int'l report, Cantarell had proven reserves of 9.8 Gb. Cumulative production at the end of 2002 was 9.2 Gb, suggesting an

EUR of ~19 Gb. I have also recently seen a reported EUR value of ~16 Gb. If the ultimate recovery is ~19 Gb, production should decline at an average rate of ~10%/year after 2005. A recent article concerning Cantarell (http://biz.yahoo.com/ap/051208/mexico_oil_output.html?.v=1) states that Cantarell's production rate is expected to decline at about 10%/year for the period 2004-2008. In recent years, the state oil company of Mexico, PEMEX, has injected nitrogen gas into the Cantarell reservoirs. Nitrogen injection caused the production rate to increase from ~1 mb/d in the 1990s to ~2 mb/d for 2003-2005. Although gas injection dramatically increased the production rate for a while, it doesn't appear that it has significantly increased the EUR.

Based upon production and EUR data for the fields discussed above, technology appears to have little impact on ultimate recovery. Technology has allowed producers to achieve high production rates but that has led to high decline rates. Those claiming that technology increases ultimate recovery appear to be basing that claim on oil reserves data in Oil & Gas Journal and World Oil. Reserves data are seriously flawed due to exaggeration of reserves, lack of updating for reserves figures, lack of a universally recognized definition for reserves and lack of independent verification. Reserves data should not be used to make conclusions about technology's impact on ultimate recovery.

Roger Blanchard is author of the book "The Future of Global Oil Production", McFarland and Company Publishers, 2005. He has also written papers concerning North Sea and Non-OPEC oil production.

Times Article Viewed: 10216
Published: 03-Feb-2006


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