August 2007

Establishing reserves for unconventional oil: Reason vs. definition

Unconventional reserves often fall into the category of undeveloped. But does that mean they aren't proved? Or that they never will be developed?

Vol. 228 No. 8  


Establishing reserves for unconventional oil: Reason vs. definition

Unconventional reserves often fall into the category of undeveloped. But does that mean they aren’t proved? Or that they never will be developed?

The short answer to both of the above questions is “Of course not.” But when the overwhelming majority of such reserves are not being developed, some skepticism is in order as to whether they are truly proved undeveloped. After all, if they are economically developable using today’s technology, under present conditions of price and governmental policy, then one must ask why the vast majority of such reserves are just lying there. If, by the definition of proved, it isn’t prices or economics, then what is the problem?

There are only two organizations that systematically gather and publish information on world oil and gas reserves. Both of them are trade journals; World Oil is one of them, OGJ is the other. This reserves data is then repeated in numerous publications and by national and international agencies. Sometimes, a particular country’s numbers are altered when they are republished, because the organization may have better information than the trade journals. That is well and good. This is an impossible task to do precisely, given that detailed field-by-field, country-by-country reservoir data is not publicly available, and even if it were, it would keep a large company busy year round crunching the numbers.

World Oil simply asks governments, governmental agencies and organizations what their reserves are, as we have been doing for 62 years. In most cases, the estimates seem reasonable, but in some instances, especially where vast undeveloped, unconventional reserves are involved, the large quantities reported to us must be scrutinized. These quantities are often so vast that they affect public policy discussions and estimates of future world supply.

Interestingly, the 2000 USGS world assessment does not include oil shale, heavy oil (<15°API) and “tar” sands, but it does recognize their potential.


SPE recently published its updated reserves definitions (Feb. 2007). The most important defining language remains:1

“Proved reserves are those quantities of petroleum which, by analysis of geological and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under current economic conditions, operating methods, and government regulations. Proved reserves can be categorized as developed or undeveloped.”

Economic issues. Determining economic factors become much more complex with unconventional resources, such as extra heavy oil, bitumen and oil shale (kerogen). These might include the cost and availability of energy that is added to the reservoir. They might also include the cost is of upgrading a kerogen or bitumen resource to a usable form, and whether surface mining techniques should even be considered an oilfield activity. SPE addresses this issue in section 5.10, Estimated future rates of production:1

“In estimating future rates of production…proper consideration should be given to… the energy inherent in, or introduced to, the reservoir…”

In the case of steam-assisted extraction, a large amount of energy must be added to the bitumen or extra-heavy-oil reservoir for extraction. Even surface mining requires a lot of energy.

Complicating the problem of what should be included in the economics of these unconventional resources is the fact that they are more connected to the upgrading facility than are conventional oils. In fact, they need to be upgraded just to get to conventional oil status, and have low value as extra-heavy oil, bitumen or kerogen (oil shale). This upgrading requires more energy and money, and because not just the value, but also the volume of these resources changes upon upgrading, it brings up the question of where reserves barrels are counted. From SPE’s reserves “mapping” subcommittee:2

“Reserves Reference Point: …Custody transfer can be obscured by varying ownerships or sharing of processing facilities. For example, in integrated extra-heavy oil or bitumen production and processing projects, it is not clear if the quantity for reserves estimates is the quantity at the upgrader inlet or synthetic crude oil measured at the upgrader outlet.”

That same document points out that the US Securities and Exchange Commission has accepted “extra-heavy oil as being part of conventional oil and gas operations, excludes oil shales, does not address gas hydrates and is currently ambivalent on bitumen. SEC excludes mined bitumen, provisionally includes bitumen recovered by in situ methods and is currently studying whether upgraded synthetic oil can be defined as the sales product. The Canadian regulations include all bitumen as petroleum reserves.”2

Other economic issues include the cost of the explosive population growth that is often necessary to exploit the resource, which is frequently in remote, unpopulated areas. For example, in the case of the Canadian bitumen-rich sands, a 2005 report identified the need to invest $1.2 billion in public infrastructure in the Ft. McMurray area during the 2005-2010 period.3 The proposed investment covers improvements to regional highways, upgrades to municipal water and sewer systems, new schools and recreation facilities, and expanded health facilities. It would not be practical to attempt to tax the few local citizens that were originally there to pay for the explosive population growth.

The issue of government policy and the role that it plays in economics can vary tremendously. Besides taxes and royalties, public monies can be directly applied to subsidize an oil or gas project. For example, bitumen production and upgrading is electricity intensive. So, the source of that electricity, its fuel and whether public monies are used become cost considerations. If electricity is generated at a nuclear power plant, which is considerably federally subsidized, and that power is sold to an oil company at a favorable rate, then public monies support the oil project’s economics.

Incidentally, there is a proposal to build a nuclear power plant near Ft. McMurray for bitumen projects. Whether steam and hydrogen would be produced directly and then transported modest distances, to the surrounding projects, or whether only electricity would be generated, and it, in turn, would be used for steam and hydrogen production, is unclear. Thus far, it’s only an idea, and it is not moving forward.

When it comes to federal support, self-serving interest is historically routine. It would not be at all surprising if some governmental official, whether in Ottawa, Caracas, Washington or elsewhere, had a financial interest in the resource play, even if only peripheral, such as real estate or vote buying, whether that official was elected, appointed or anointed. Thus, it’s important to keep abreast of what public monies the political winds might blow into making a resource economic.

Environmental costs. Water use might be a limiting factor, especially in steam-related recovery. Water re-use is one option. Alternatively, if cheap water is not available, non-potable formation water can be drilled for and produced. This brine can be upgraded-at a cost-to a quality sufficient for steam production. Water in Canadian bitumen production is a big public policy issue, but so far, the public has not chosen to curtail production.

Stockpiling of sulfur is occurring in the Ft. McMurray area. The resource typically has 4-6% sulfur, and the global sulfur market is crummy. Sulfur production could reach 10-12 million tons per year by 2030, which is equal to about half of the internationally traded sulfur worldwide, and is almost double Canada’s seaborne exports today.4 Still, sulfur is needed in some industries, and some of it can be sold or given away.

Tailings/fluid tailings and associated settling basins are a huge problem. They contain toxics such as metals, and wildlife must be kept from them. These tailings are being stockpiled in huge lined ponds, and their volume will reach well into the billions of gallons in time. Although there is ongoing research, there is no solution as to what to do with these ponds-the toxics and solids are simply not settling out as originally hoped. So far, the public has chosen to allow this stockpiling and not curtail production. There are other land use issues that need to be resolved.

In countries that care-and Canada is a Kyoto signatory-greenhouse gas emissions could have a big impact on resource recovery. Heavy oil and bitumen extraction and upgrading produce much more greenhouse emissions than do conventional oils. Some of the experiments to reduce energy costs involve burning high-carbon fuels such as coke or the bitumen itself. If additional costs are incurred-from sequestration, the purchasing of offsetting carbon credits, or something else-such costs will have to be included in the reserves calculation. In addition, there are several other air-quality problems that need to be resolved.


As if the above problems weren’t enough, lack of natural gas is one problem that nearly everyone agrees on regarding Canadian bitumen. They just don’t agree on whether it should apply to reserves estimation. Current gas usage rates for bitumen extraction and upgrading (ignoring worker/population use, and some electricity generation) range from 1.23 to 1.98 Mcf/bbl.5 This applies to in situ extraction, which is 80% of the estimated reserves.

Putting it simply, to develop and upgrade 170 billion bbl of in situ bitumen, using today’s technology, would require 340 Tcf of gas. Since normal life elsewhere in Canada (and for that matter, the US) must be maintained, this implies truly absurd levels of gas reserves. While the world has enough gas to get the job done, whether it can be delivered to Ft. McMurray is not at all certain. Neither is it apparent whether this issue should be considered in estimating reserves.

Here’s how the Oil Sands Technology Roadmap puts it:4

“In this scenario [current mix of projects], natural gas usage would rise from 10% of combined WCSB, Coalbed methane and Mackenzie supply by 2012, to an unthinkable 60% or more by 2030. Such a demand level, combined with competition from other markets in the face of dwindling reserves, will only drive price increases. LNG imports into North America may begin to set price levels. The ‘business as usual’ case is clearly unsustainable and uneconomical.”


The truth is, unconventional resources such as Canada’s 170 billion bbl of bitumen probably can get produced and upgraded. But it will be done with tomorrow’s technology, not today’s. Novel experimental processes offer the hope of in situ upgrading, such as with Shell’s Mahogany oil shale project, which enriches what gets produced with hydrogen, and leaves some of the carbon behind. A process that could change Canada’s bitumen production picture is the Opti/Nexen Long Lake project, where upgrading occurs in the field in a nearly closed-loop process, where much of the energy for steam extraction of the bitumen comes from the upgrading process, which includes a gasification stage. And there are many others.

However, such optimism is not allowed in the reserves definitions. The root of the problem, if indeed it could be called a problem, is that the overwhelming majority of the local population where these deposits occur are in favor of development. This is very evident in Alberta. And while there are various concerns and some naysayers, the bitumen projects offer so much opportunity for increased wealth that dissent is not likely to stop the growth of these projects. They seem to like being called the “Saudi Arabia” of unconventional oil, and equally like the massive increase in reserves that they were given in 2001.


We began this by saying skepticism was in order when examining massive proved undeveloped reserves. By current reserves definitions, it’s possible to have reserves that will take centuries, even millennia to produce. But clearly, intuitively, reserves that can be recovered under “current economic conditions, operating methods,” but would take centuries or millennia to produce, are a contradiction in terms. “Current” and “centuries” cannot reasonably coexist.

Take, for example, that, at current production rates, it will take 480 years to produce Canada’s claimed 175 billion bbl of proved reserves. Most of that is bitumen. Suppose bitumen production were increased to just 5 million bpd. Then it would take 90 years to produce. But no one believes that this level of production can be achieved using “current economic conditions, operating methods, etc.,” even though most people, including World Oil, believe that technology breakthroughs will ultimately allow those production rates to be achieved.


When we look at governmental reserves figures, particularly unconventional undeveloped reserves, we mull over all of the issues raised in the above discussion. In the case of Venezuela, we discount their claimed 77 billion bbl in reserves, to 52 billion bbl. With Canada’s proved oil reserves, as previously discussed, at current production levels, it would take 480 years to produce. We would like to see that pace pick up.

In the meantime, we will base these unconventional reserves on a somewhat arbitrary method of 50 (years) times current production capacity, which is the longest that Capex will last. Note that this is similar to rules used by stock market exchanges. Reserves not counted as proved can be reclassified as probable, undeveloped. As new technology becomes established, we will adjust our numbers accordingly.

Obviously, what is needed is a new set of definitions specifically for unconventional resources. Everything discussed above should be included:

  • Are barrels and costs counted before or after the upgrader?
  • Should deferred environmental costs be considered, especially if sustainability is otherwise not possible?
  • Should public infrastructure costs be considered?
  • Should the location, quantity and ultimate availability of energy, such as natural gas, be considered?
  • Should there be a limit to the time it would take to produce the resource?
  • Are production methods revelant (e.g., surface mining).
  • Should optimism be considered and, if so, to what extent, in estimating proved undeveloped reserves.

Except for the “which side of the upgrader” issue, our 50-year-times-current-capacity rule is easily applied. Perhaps the old Canadian term “established reserves” should be resurrected, which is defined as proved plus half of the probable reserves. Whatever the definition, we need it to speak directly and unambiguously to the issue of establishing exactly how unconventional, proved undeveloped reserves should be estimated. WO


1  Standards pertaining to the estimating and auditing of oil and gas reserves information, Approved by SPE Board in June 2001. Revision as of February 19, 2007.
2  SPE’s Oil and Gas Reserves Committee, “Mapping” Subcommittee Final Report, Comparison of selected reserves and resource classifications and associated definitions, Dec. 2005.
3  Oil sands industry update, Alberta Economic Development, December 2005.
4  Oil sands technology roadmap, Alberta Chamber of Resources, January 2004.
5  Oil sands industry outlook presentation to the national energy board Bob Dunbar, President, Strategy West Inc. Calgary, May 5, 2006.


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