Reserve
Growth: Technological Progress,
or Bad Reporting and Bad Arithmetic?
by J.H. Laherrère*
Geopolitics of Energy Issue 22 n°4, p7-16, April 1999
*Jean Laherrère
worked for TOTAL for thirty-seven years in a variety of successively more responsible
roles encompassing exploration activities in the Sahara, Australia, Canada and
Paris. Since retiring from the TOTAL,
Mr. Laherrère has consulted worldwide on oil and gas potential and production. He has served on the Society of Petroleum
Engineers/World Petroleum Congress ad hoc committee on joint definitions of
petroleum resources and the task force on “Perspectives Energie 2010-2020” for
the Commissariat Général du Plan.
Introduction
On a visit to Calgary
this April, I noticed a weather forecast in the newspaper that mentioned “pop.
30 percent.” Having lived in Calgary
from 1966 to 1972, I knew that it could snow at any time, and I was not
surprised to see some snowflakes in the afternoon. Had nothing changed in the past twenty years? In fact, there has been a big change: the use of probability, as “pop” is the
probability of precipitation.
While the
concept of probability evidently has entered the daily life of Calgarians, it
has yet to enter the assessments of oil and gas reserves in the provinces of
the Western Canadian Sedimentary Basin.1
In Alberta, Saskatchewan and British Columbia, oil and gas reserves are
reported by the operators as “proved reserves”, following U.S. practice. In the U.S., the oil industry currently is
obliged by Security and Exchange Commission (SEC) rules to report only proved
reserves, ignoring probable and possible reserves. Proved reserves are those deemed to be recoverable, based on
current and foreseeable economic and technological conditions, with “reasonable
certainty”. The practice of ignoring
probable reserves inevitably has led to large upward revisions, which
mistakenly are attributed to advances in technology, when in reality they are
an artifact of flawed reporting.
The Use (Misuse) of the Term “Proved Reserves” in the
United States
To better
understand the use (and misuse) of the term “proved reserves” in U.S. reporting
practices, it helps to begin with a few recent observations on the topic:
According to a
recent study by J.R. Ross, “The term ‘reserves’ often is treated as if it were
synonymous with ‘proved reserves’. This
practice completely ignores the fact that any prudent operator will have,
internally at least, estimates of ‘probable and possible reserves’. These reserves plus cumulative past
production is ‘ultimate recovery’, often called initial reserves and they
exclude field growth, which is due to a failure in the industry’s ability to
assess uncertainty correctly”.2
In 1994, the
USGS noted the dilemma presented by traditional U.S. reporting practices, and
specifically, the tendency to attribute reserve growth, and indeed all upward
revisions in estimates of proved reserves, to technological progress: “Oilfields brought on line in the early part
of this century continue to produce beyond expectations. This is partly an artifact of reporting, and
partly an enhanced understanding of reservoir heterogeneity and technological
innovation....The concept of reserve growth may be the single most challenging
issue in conducting a national oil and gas assessment.”3
In assessing the U.S. DOE
estimates in 1998, John D. Grace notes that reserve growth for discovered
fields estimated at around one third, and for undiscovered fields, at around
one quarter of the ultimate resource.
He observes that undiscovered liquids, estimated at 83 billion barrels
by the DOE, would take 615 years to discover at the present rate of new field
discoveries.4 Attanasi objected to this arithmetic, arguing that it would take
only 62 years to discover the 83 billion barrels of undiscovered liquids. This is based on the supposition that field
growth will increase the estimate for reserves at recovery by a “growth”
factors of ten, 100 years later.
However, it needs to be pointed out that the “ten-fold” factor is outdated. It relates to estimates on “old” onshore
discoveries and is based on a limited application of seismic technology. A recent study by the MMS on modern
estimates of offshore reserves in the Gulf of Mexico applies a growth factor of
only 4.5. Furthermore, it will take a
long time—over 50 years—to deliver the actual production volumes. With production in the U.S. now in sharp
decline, the development of undiscovered reserves, and field growth, are needed
now.
Currently, there are
various ways to estimate reserves—volumetric, materials balance, production
decline, simulation—using different approaches, such as deterministic (giving
only one value) and probabilistic (giving a range, usually minimum, mean and
maximum or P90, P50 and P10). In the
U.S., the “accepted” practice is to report proved reserves. In the rest of the world (excluding the
Russian Federation) the practice is to report proved plus probable reserves
(defined as P50). In fact, the
“theoretically” correct practice is to estimate reserves as the mean (expected)
value, which corresponds roughly to a probability of 40 percent.
As mentioned above, the SEC
rules define proved reserves as those that will be recovered with “reasonable
certainty”. It is interesting to note that
the U.S. Food and Drug Administration uses the same term for authorizing the
sale of a new product, such that there is reasonable certainty of it causing
“no harm”. The current Society of
Petroleum Engineers/World Petroleum Congress (SPE/WPC)5 rules and guidelines cite
two different definitions for “proved” reserves:
(i) the deterministic
definition, whereby proved reserves are defined as those recoverable with
“reasonable certainty” and a high degree of confidence, and
(ii) the probabilistic approach,
where proved reserves are defined as those recoverable with a probability of
better than 90 percent.
These are all ambiguous
definitions, allowing anyone to use the estimates that suit them.
Statistics from
the U.S. DOE for additions to proved crude oil reserves over the past ten years
are shown in Table 1.
Table 1
|
|
Additions |
Revisions |
|
|
|
Million
Barrels |
% |
% |
|
New Field Discovery |
169 |
9 |
|
|
New Reservoirs Discovery |
133 |
6 |
|
|
Extensions |
440 |
21 |
|
|
Adjustments |
239 |
12 |
|
|
Revisions: |
|
|
|
|
Total
Additions |
2,048 |
|
100 |
SOURCE: U.S. DOE Annual Reports, 1996 and 1997.
A close inspection
of these data suggests that U.S. “proved reserves” in fact represent the most
likely case—with a probability of recovery of around 65 percent—and not the 90
percent probability case required by the SPE/WPC.
In short, the
bulk of U.S. “reserves growth” primarily can be attributed to faulty reporting
practices, including that of reporting only “proved reserves”. Technological progress is not the culprit.
Bad Addition of Proved Reserves
The practice of
simply adding together the “proved” values of a large number of fields in a
country underestimates proved reserves for the country. The degree of underestimation increases with
the probability of the proved reserves for the fields. Logically, only the mean proved reserves for
a country will be equal to the sum of the mean proved reserves for each field
in that country. Similarly, global
proved reserves are not equal to the sum of proved reserves in every country,
as reported in many industry publications.
The correct estimate—mean expected global reserves—would be considerably
higher. As one of the best U.S. experts
on reserves wrote in 1996, “An industry that prides itself on its use of
science, technology and frontier risk assessment finds itself in the 1990s with
a reserve definition more reminiscent of the 1890s illegal addition of
proved reserves”.6
Canada: A Case
Study
Surprisingly, no
serious study of reserves growth has been made at either the provincial or
national levels in Alberta, Saskatchewan and British Columbia, where only “proved
reserves” as provided by the operators (and amended by the agencies) are
reported. By ignoring estimates for
probable plus possible reserves, the provinces are effectively underestimating
reserves. Summing proved reserves
across fields aggravates the problem.
In addition, valuable data may be lost in the details of a
classification system based on individual pools, and not fields, which the rest
of the world reports.
As in the United
States, it is likely that the western province’s estimates for proved reserves
actually represent the most likely case (probability of recovery of about 65
percent) and not the 90 percent probability required by the SEC/WPC. Once again, a significant portion of
“reserve growth” may be attributed to faulty reporting guidelines, and not to
technological progress, nor to the proving up of undiscovered resources.
The time series data on
pool reserves provided by the provinces are shown in Figure 1. Total reserve growth—including growth due to
revision and growth due to technological progress—is represented by the gap
between the current value of the initial established reserves and the backdated
value using 1997 estimates. In this
figure, the variation over time in the ratio between backdated reserves and
current estimates of initial proved reserves indicates the approximate
contributions of revision versus technological progress to overall reserves
growth.
Figure 1
In Figure 2, the ratio
between backdated values and current reported values versus time since discovery. At about 25 years following discovery, the
ratio is calculated at around 1.1 for Alberta and British Columbia. It exceeds 1.6 for Saskatchewan, where the
bulk of reserves are heavy oil—a sub-component of the oil industry that has
been enhanced significantly by technical progress. When the time frame is increased to 30 years past discovery rate,
the ratio climbs to over 3 for British Columbia and Saskatchewan, and to 2.2
for Alberta. As anticipated, the
significant increase in the ratio for Alberta and British Columbia is due to
advances in seismic technology.
Figure 2
While using
expected (mean) values will result in “statistically correct” estimates for
reserves, it also means that the individual estimating the values will be wrong
as much as 60 percent of the time.
Since experts—in the oil industry, as elsewhere—do not like to be wrong,
there is a strong incentive to report conservative values. The issue is complicated by the nature of
the incentive. Reserves for small
projects may be overestimated to pass economic hurdles, while those for large
projects tend to be underestimated because the lower economic threshold allows
for caution.
Furthermore as
Ross has written, public estimates for reserves often are not those used
internally, where a range normally is applied.
The very act of publishing reserves values is political, and depends on
the desired image that the publisher wants to present for the company or
country. For example, the OPEC
countries roughly doubled their reserves in 1987 without making any major new
discoveries when quota calculations became based on reserves.7
The “Culture of Growth”
Everybody loves
growth, as we live in a culture of high expectations. Progress, technology and growth are expected to solve all the
world’s problems. It excuses us from
facing any problem “today” in the hope that growth will solve it later. At the same time, companies and countries
love to show that they are growing, in the hope that the stock market (and
stock options) will continue to grow too.
The prospect of perpetual “reserves growth” is appealing, and indeed
partially explains why conservative estimates for crude reserves are so popular
within the oil industry. Those who
choose to speak about the end of “cheap oil” generally are limited to a handful
of retired geologists (Ivanhoe, Campbell, Laherrère, Perrodon...), university
professors (Startzman, Bartlett…), and oil company CEOs (Bernabe, Bowlin…) a
few days before departing the oil industry.
Technology
Whereas the oil
industry uses the most modern techniques to increase production, it appears to
be with the worst (outdated) technology when it comes to reporting
reserves. A company that is able to
attribute perpetual reserve growth to technological progress or its management
skills, provides an excellent image to its shareholders. New technology primarily increases
production rate and lowers costs, but rarely is responsible for “reserve
growth” in fields holding conventional oil.
On the other hand, new techniques are needed to improve recovery from
unconventional fields.
This proposition
can be illustrated by a few examples.
In Figures 3 through 6, annual production versus cumulative production
is plotted for four giant oil fields in the U.K., U.S. and FSU. When a field is in decline, the plot follows
a straight line (or an obvious curved line), which can be extrapolated until
annual production hits zero (or the economic threshold). The final value for cumulative discoveries
is the ultimate recovery of the field.
The time series
for the fields support the proposition that the “real” reserves (ultimate
recovery) of giant fields rarely are affected by advanced in technology.
Case 1: North Sea
Forties
The reserves of the
Forties field in the North Sea were reported to have been increased when a
gas-lift and fifth platform were installed in 1987. In fact, while the annual production rate did increase above the
normal rate of decline for about two years following, there was no change in
ultimate recovery (see Figure 3). The
“decline ” estimate for ultimate recovery was unaffected by the new technology
and investment.
Figure 3
Case 2: East Texas
The East Texas
field (see Figure 4) was reported to hold 6 billion barrels in reserves over
1975-1991, although production in the field was declining from its 1973 peak at
5 percent per year. In 1992, the
field’s ultimate reserves were reduced to 5.4 billion barrels and the decline
rate increased to 10 percent per year.
Technology made no difference.
Figure 4
Case 3: Wilmington
The Wilmington
heavy oil field (see Figure 5) was unitized in 1960 in order to arrest surface
subsidence of over 8 meters and to introduce waterflooding. Production peaked in 1970 and has declined since
at a steady annual rate of 6 percent, notwithstanding the intervention of new
technologies including steamflood and horizontal wells. Estimates for ultimate recovery for this
field have been revised repeatedly:
from 2.6 billion barrels in 1967-1970, to 2.4 billion barrels
in1972-1983, to 2.8 billion barrels in 1989-98. A decline curve analysis, if completed in 1975, could have
pointed to ultimate recovery of 2.85 billion barrels—a figure remarkably close
to current estimates.
Figure 5
Case 4: Samotlar
In 1997, the
largest oilfield in the FSU, Samotlar (see Figure 6), was reported to hold 27
billion barrels in ultimate reserves, with a maximum theoretical recovery of 50
percent. Now the estimate is down to 24 billion barrels. The decline from 1982
to 1990 was a constant 6 percent per year.
Since 1991, the field has been plagued by operational problems. Halliburton recently has signed a contract
to drill 4,500 new wells, about half of which will be horizontal8. The company’s forecast for annual production
over 1999-2020 fits the pre1990 decline and extrapolating suggests an ultimate
recovery of only 20 billion barrels.
Figure 6
It is not
surprising to see a downward revision to Russian oil reserves. The negative reserves growth can be attributed
to the unique “Soviet” system of reserve classification which ignored
technological and economic constraints.
This was confirmed by Khalimov in 1993:
“The resource base [of the FSU] appeared to be strongly exaggerated due
to inclusion of reserves and resources that are neither reliable nor
technologically nor economically viable”.9 The Russian practice, of overestimating by
neglecting economic and technological constraints is a stark contrast to the
U.S. practice—underestimation by neglecting probable reserves. In both cases, the faulty reporting for
reserves in individual fields is compounded when the data are aggregated to
national totals.
Bad Reporting of the Discovery Year
When a field
extends into another country or concession, it commonly is given another name,
and each part of the field is given a unique discovery date. To cite only one example: the “North Field” in Qatar—the largest gas
field in the world—was discovered in 1971, and extends into Iranian
territory. The extension was not drilled
until 1991, and is now known as the South Pars gas field. As result, the “official” public database
now reports a “significant” increase in new gas discoveries in 1991. Not surprisingly, a significant portion of
the “new” 1991 discoveries can be attributed to the South Pars gas field.
If these
reserves were properly backdated to the real year of discovery (1971), the
public record of new discoveries for 1991 would have to be adjusted
significantly—i.e., discoveries would be reduced by a factor of two for oil,
and a factor of six for gas.
Reserves Growth and Remaining Reserves
As shown in Figure 7,
current estimates place the world's total (proved+probable) annual discovery of
oil and condensates at approximately 10 billion barrels. With global production approximating 25
billion barrels per year, annual production exceeds discoveries by a
significant margin. In short, there is
a global "oil deficit" of approximately 15 billion barrels per year. The gas deficit is almost nil, at 5 Tcf per
year.
Figure 7
Remaining
reserves can be expected to remain constant if annual reserves growth for oil
is 1 percent, equating to additions of 16 billion barrels per year. If, however, reserve growth is half smaller
at 0.5 percent annually (8 billion barrels per year)--then the "oil
deficit" will translate into a reduction in "remaining
reserves", by approximately 10 billion barrels per year.
This "oil
deficit" cannot be sustained indefinitely. If production continues to exceed discoveries, global oil production
is certain to begin falling, reflecting the increasing scarcity of global oil
reserves. This development can be
expected to affect global oil supplies sooner rather than later. As shown in Figures 3-6, a study of the
major U.S. oil fields and the world's giant oil fields suggests an aggregate
annual field "growth rate" of only 0.5 percent. This estimate will continue to decline as
the world's largest oil fields enter into the advanced stages of maturity.
Conclusion
The exclusive
use of the “proved” reserves classification in the U.S. and the three western
Canadian provinces provides a poor—misleading—inventory of reserves in
discovered fields while simultaneously preventing industry analysts from making
a thorough assessment of undiscovered resources. To further aggravate matters, simply adding estimates for proved
field reserves together to arrive at an estimate for a country increases the
underestimation problem. The resulting
“reserve” growth gives a false image of what is really happening. At the same time, the size and volume of new
discoveries of conventional reserves are decreasing. While technology has enhanced the production of conventional
reserves, it has had little impact on ultimate reserve values.10
Outside North
America and the Russian Federation, the use of “proved plus probable”
reserves—not surprisingly—leads to lesser reserves growth. Perpetual reserves growth is good for
company image and equity values.
As a result, a
sound inventory of the world’s discoveries has yet to be produced and
published. A study using mean
(expected) reserve values would almost certainly point to a coming oil crisis,
and higher oil prices. Oil prices are
mainly political, and much depends on Saudi Arabia, but for many the notion of
reserve growth is the same as saying that “a bird in the hand is worth two in
the bush”.
Acknowledgement
Thanks to
Petroconsultants for allowing use of their data.
Footnotes
1In contrast,
reserves for Newfoundland and the MacKenzie-Beaufort basins are based on
probabilistic calculations.
2Gaffney, Cline
& Associates, “Nonstandard Reserves Estimates Lead to Resource
Underestimation”, Oil and Gas Journal, March 2, 1998.
3“The uncertainty of
estimating growth hydrocarbon reserves”, June 1994. [need more info.]
4Grace, John D.,
“U.S. Resource Estimates Give Insights to Key Oil, Gas Plays”, Oil and Gas
Journal, March 31, 1998.
5SPE/WPC, 1997.
6Capen, E.C., “A Consistent
Probabilistic Approach”, SPE Reservoir Engineering, February 1996, 11(1).
7Ross J., “Non standard
reserves estimates lead to resource underestimation”; Oil & Gas Journal,
March 2, 1998.
8Oil and Gas Journal,
November 30, 1998, pp. 77-78.
9Khalimov, E.M.,
“Classification of Oil Reserves and Resources in the Former Soviet Union”, AAPG
77(9), September 1993, p. 1,636.
10In the case of
non-conventional reserves, new technology can have a major impact, however.