Parabolic Projection of Conventional Natural Gas Production from the Western Canada Sedimentary Basin

John H. Walsh
Energy Advisor

Note: The three figures of this paper are not included with the text below. These may be obtained in hard copy form by contacting the author at


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.


The Western Canada Sedimentary Basin (WCSB) has historically been by far the main source of natural gas in Canada. This large Basin is defined geographically by regions in Alberta, north-eastern British Columbia, Saskatchewan, and southern regions of the Northwest Territories. Although significant natural gas production began from the Sable Island field off the coast of Nova Scotia in late 1999, with possible additional production to come later from Newfoundland waters (including off-shore Labrador), and though new gas lines may be built in this decade to move gas from the Canadian Arctic regions (together with gas from Alaska) to southern markets, future supplies from the WCSB will remain important to the Canadian gas industry for many years. Notwithstanding these new conventional sources, gas derived from non-conventional sources may also be required. Of the latter generally more costly new supplies, Coal Bed Methane (CBM) is considered the next most likely source which already accounts for some 5% of U.S. domestic production. In Canada, a project has begun to assess the use of captured carbon dioxide as the flushing media in this process.1 In this variation of the CBM process, more carbon may be sequestered in the depleted coal than released in the displaced product methane.

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 forward-looking staged parabolic method was applied to project gas production from the WCSB, including the estimation of the timing and magnitude of the peak, based upon resource potential data. Limitations of the application of this technique to natural gas resource assessments are given in Reference 6. In essence, the time-series for natural gas production may be expected to depend more upon market factors such as price than in the equivalent case of oil, and thus this type of projection is inherently more variable in the case of gas. Nevertheless, the WCSB is approaching maturity with the predicted time-to- peak only eleven years in Case 1 and six years in Case 2.

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.

Case 1: 61.87 + Qs - q0 = 335
Case 2: 61.87 + Qs - q0 = 264

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.


For Case 1, with Ultimate Gas Resources of 335 Tcf, peak production of 6.88 Tcf is expected in 2010.9. For Case 2, with Ultimate Resources of 264 Tcf, peak production is expected in 2006. National historical production data (including all sources) is included in the figures, but this introduces a negligible error as gas output from non-WCSB sources have been essentially negligible in the past. Consumption data is also included for comparison purposes. It is evident that conventional sources in the WCSB could meet all Canadian needs for natural gas for some decades to come. The effect of the reserves addition becomes progressively more important as the years pass.

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.


The Staged Parabolic Technique has been applied to two estimates of the natural gas resources of the Western Canada Sedimentary Basin published by the National Energy Board in its most recent supply/demand study released in June of 1999. In Case 1, the ultimate conventional gas resources were set at 335 trillion cubic feet based upon expert geological opinion offered in testimony by applicants before the Board. In Case 2, the ultimate resources were set at 264 Tcf. according to the cooperative studies undertaken by the Canadian Gas Potential Committee, an independent body formed to examine this question in detail. The effect of the reserves addition over time was estimated by assuming a 30% increase in the resource base in both cases with the further assumption that this added volume of gas only becomes effective after the peak is past. The generally higher prices expected in the post-peak period is assumed to cover the costs of the adoption of more costly exploration and recovery technologies at this later time.

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.


  1. Brian Hitchon, W.D. Gunter, Thomas Gentzis and R.T. Bailey, Sedimentary Basins and Greenhouse Gases: A Serendipitous Association, Energy Conversion and Management, Vol. 40, 1999, pp. 824-843.
  2. Canadian Energy Supply and Demand to 2025, National Energy Board, Calgary, Alberta, T2P 0X8. (ISBN 0-662-27950-6) June 1999. (Web:
  3. Natural Gas Potential in Canada, An assessment prepared by the Canadian Gas Potential Committee dated 1997, an organization affiliated with the Department of Geology and Geophysics of the University of Calgary. P.O. Box 20032, Bow Valley Square, Calgary, Alberta, T2P 4H3.
  4. C.D. Masters, D.H. Root and E.D. Attansi, Resource Constraints in Petroleum Production Potential, Science, Vol. 252, 12 July 1991.
  5. J.H. Walsh, Parabolic Projection of World Conventional Oil Production Based on Year 2000 Resource Assessment of U.S. Geological Survey, April 2000. (Available in abridged form on the Web at
  6. J.H. Walsh, Parabolic Projection of World Conventional Natural Gas Production Based on Year 2000 Resource Assessment of U.S. Geological Survey, May 2000. (Available in abridged form on the Web at
August 2000
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