Establishing reserves for unconventional oil:
Reason vs. definition
reserves often fall into the category of undeveloped. But does
that mean they aren’t proved? Or that they never will be
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
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,
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
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
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.
THE GAS ISSUE
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.
THE MILLENNIA ISSUE
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
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.
NEEDED: A NEW DEFINITION
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
- Are barrels and costs counted
before or after the upgrader?
- Should deferred environmental
costs be considered, especially if sustainability is otherwise not
- 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.
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.
sands industry update, Alberta Economic Development, December 2005.
4 Oil sands technology roadmap, Alberta
Chamber of Resources, January 2004.
sands industry outlook presentation to the national energy board
Bob Dunbar, President, Strategy West Inc. Calgary, May 5, 2006.