by Jean H. Laherrère
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.4Attanasi 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|
|New Field Discovery||69||9|
|New Reservoirs Discovery||133||6|
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.
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.
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.
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 advances 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.
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.
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 in 1972-1983, 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.
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 pre-1990 decline and extrapolating suggests an ultimate recovery of only 20 billion barrels.
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.
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.
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”.
Other Voices Back
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 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.
Thanks to Petroconsultants for allowing use of their data.
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.
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.