Two assessments of the resource base of the Western Canada Sedimentary Basin were projected parabolically to estimate the timing and magnitude of the peak in production of natural gas from conventional sources. Two estimates of the ultimate gas resource were published in the June 1999 report of the National Energy Board titled Canadian Energy Supply and Demand to 2025. The resource base was given as 335 trillion cubic feet (Tcf) for Case 1 in geological testimony submitted by applicants to the Board and 264 Tcf for Case 2 as published by the Canadian Gas Potential Committee, an independent organization established to study this matter. These estimates were then interpreted by the forward-looking parabolic technique employed in previous papers.
The peak production of conventional natural gas from the Basin is predicted at 6.88 Tcf/year in 2010.9 in Case 1 and 6.26 Tcf/year in 2006 in Case 2. The reserves addition was assumed to be 30% added to the total potential resource and operative only after the peak is passed. These projections are plotted over time along with historical production and consumption data.
Natural gas plays an important role in reducing carbon dioxide emissions from the fossil fuels. This convenient source of energy is the least carbon-intensive of these fuels and is generally easier than the others to consume at high efficiencies of energy conversion. Gas is now important in the generation industry in either combined-cycle installations, presently the preferred new source of electricity at margin, or in cogeneration (combined heat and power) mode. With the advent of fuels cells for both stationary and mobile applications, natural gas is the cheapest source of hydrogen-the fuel generally required-although there are now research efforts to allow the direct use of gas in these efficient energy conversion devices with no need for prior reforming to hydrogen or conversion to liquids such as methanol.
Very large resources of natural gas exist in the Middle East and in some other countries a large fraction of which may be `stranded' in regions with only limited local outlets. This gas may be moved in the form of Liquefied Natural Gas (LNG) in cryogenic tankers. In 1999, 25.6% of all the gas in international trade was moved by this means. The resources known are sufficiently large that gas shipped in this way could prove price controlling at U.S. coastal locations. If so, this option may limit the applicability of more expensive gas supply approaches for many years, particularly the ultimate price-capping alternative of producing synthetic gas from coal. One such facility is operating in North Dakota.
For these reasons, it is important to estimate the future track of natural gas production from the WCSB. The National Energy Board,2 in its supply/demand study published in June of 1999, has projected this production and also prepared estimates of the potential and the timing of supply from other sources including CBM. The resource base data used in this study was taken from this report. The `Ultimate Resources Potential' was set at 335 Trillion cubic feet (Tcf) for conventional gas from the WCSB in Case 1. This value was chosen by the Board from submissions made in connection with applications for the expansion of the pipeline system prepared by consultants to TransCanada PipeLines Limited but adjusted by the Board to account for the higher resources now expected in the southern territories (southern regions of the Yukon and the Northwest Territories). In Case 2, the ultimate potential was taken as 264 Tcf for conventional gas from the WCSB as assessed by the Canadian Gas Potential Committee,3 an independent cooperative group formed to study this question.
The staging year was chosen to be 1988 though a check of cumulative production to that year was not good. The NEB value of 102 Tcf for cumulative production from the Western Canada Sedimentary Basin to the end of 1997 was used to arrive at 61.87 Tcf for this value for the end of 1988 by deducting annual output year-by-year. This value compares poorly with the value of 73.1 Tcf given by Masters et al4 for all of Canada for that year. These values should be closer because only small quantities of gas were produced from other sources in the country up to that time. The value calculated from the NEB data of 61.87 Tcf was used in the following calculations to be consistent with other information provided in the Board's report. No explanation for this discrepancy is known.
The first step in the iterative calculation method devised to derive the staged parabola involves checking for internal consistency between the production in the staging year of 1988 and 1999, the most recent year for which production statistics are available. The known quantity of gas produced between these two years is 51.53 Tcf. The area under the parabolic curve is first estimated as the sum of a rectangle and a right-angled triangle which totaled 49.14 Tcf - a difference of 4.9%. This discrepancy is too large to apply the usual solution method of choosing the parabola that passes through the most recent production year - in this case 1999. Instead, the more complex area method was employed.
The next step is to set the cumulative production to 1988 plus the area of the staged parabola less the overlap zone at the assessed endowment of 335 Tcf for Case 1 and 264 Tcf for Case 2.
This equation is solved by iterations of the ratio of the area of the overlap zone (q0 (whose boundaries are illustrated in the first two figures) to the total area of the staged parabola (Qs). The particular parabola for which the area for the eleven years between 1988 and 1999 equals 51.53 Tcf. is selected as the solution. This value checked within 0.04% in the final iteration for Case 1 and 0.13% correspondingly for Case 2. These two solutions were judged sufficiently close to be acceptable. The parabolas were then drawn in the figures on which historical gas production and consumption data were also included.
The reserves addition was assumed to be only operative after the peak in production has passed following the method used in two previous studies.5,6 The justification for this simplifying assumption is that the time to the peak is only between six (Case 2) and eleven years (Case 1). The reserves addition was assumed to be 30% of the ultimate potential and thus 335 x .3 = 100.5 Tcf for Case 1 and 264 x .3 = 79.2 Tcf for Case 2. The generally higher prices expected after the peak is reached is expected to encourage the adoption of more costly advanced production techniques in this later period. Since relatively high rates of decline in production wells have been experienced recently, the 30% assumed value for the reserves addition is considered an upper bound. For this reason, two curves are drawn for each case in the post-peak period-one including the reserves addition and the other not. It is thus possible to interpolate between these two curves for lower estimated values of the reserves addition, if preferred.
The two cases with the reserves addition are re-plotted in Figure 3 for comparison purposes. A trend line has been added to illustrate that by simple projection, conventional gas from the WCSB could meet expected Canadian needs until the 2030-2040 period. Extrapolating from the past does not, however, capture the possible additional need for gas to deal with the interrelated problems of global climate change and greater penetration of this fuel in the generation of electricity. A curve for `apparent net exports' was also added to Figure 3. These were calculated by deducting domestic consumption from production year-by-year since the latter came essentially only from the WCSB over those years. Such a calculation ignores changes in the domestic inventory of gas from year-to-year but the error introduced by this assumption is small. This plot illustrates the rapid growth in exports from the WCSB to the U.S. particularly in the last decade.
In Case 1, the peak production of 6.88 Tcf/year from conventional natural gas sources in the WCSB is predicted to occur in 2010.9 and in Case 2, 6.26 Tcf/year in 2006. This gas from conventional sources in the WCSB could meet trend-line extrapolations of total Canadian consumption until 2030-2040. In the two boundary cases studied by the Board,2 the peak was estimated to be 7.88 Tcf in 2013 and 6.90 Tcf in 2008 using different methodology.
There would seem to be little doubt that additional supplies will be needed from other regions (Northern Frontier, Eastern off-shore) and from non-conventional sources (Coal Bed Methane, tight gas?) to continue the growth of exports at their present high levels. These inherently more costly supplies may be limited in export markets by the availability of large resources of `stranded' gas in the Middle East and some other locations which could be supplied to U.S. coastal locations by tanker in liquefied form.