W. CANADA'S DEVONIAN RESOURCE SIGNIFICANT EVEN AT LOW GAS PRICES

R.R. Waghmare, S.M. Dallaire
R.F. Conn Energy Mines and Resources
Canada Ottawa

This article summarizes Part II of Geological Survey of Canada Bulletin 452, entitled Devonian Gas Resources of the Western Canada sedimentary basin (WCSB).

It provides supply curves and summary estimates of economic potential of the undiscovered natural gas resources estimated to exist in the Devonian system of the WCSB. The methodology constructed to estimate the economic potential is also described, along with major assumptions with regard to engineering inputs and economic parameters.

Economic potential measures the portion of the undiscovered resource which can be expected to provide economic investment opportunities over the long-term.

Estimates of economic potential serve several purposes. By taking costs and other economic constraints into account, a more realistic description of the resources of commercial interest to industry and relevant to public policy is provided. Estimates of economic potential are also relevant in supply/demand forecasting, supporting the resource management mandates of governments and regulatory bodies, and assisting in the strategic planning of transportation systems.

The report concludes that, in the long-term, significant economically recoverable resources remain to be discovered in the Devonian system.

TERMINOLOGY

With regard to the resource base, the term potential describes that portion of the resource that is inferred to exist but is not yet discovered.

A play consists of a family of pools and/or prospects that share a common history of hydrocarbon Generation, migration, reservoir development, and trap configuration. Mature plays are those plays in which the profile of the discovery sequence is using adequate for analysis the discovery process model, developed by the Institute of Sedimentary & Petroleum Geology. Conceptual plays are those plan,s that do not yet have discoveries or reserves but which geological analysis indicates may exist.

Concerning the economic analysis, the term supply price refers to the minimum plant-gate price for natural gas and co-products required to recover all costs associated with the exploration, development, and production of gas resources found in a pool, including a minimum discounted cash flow rate-of-return on investment.

The economic potential of a play, at a given price, is the sum of resources of all pools with estimated supply prices less than or equal to the given price. The price-economic potential relationship is defined as the supply curve, or marginal cost curve. Supply curves can be drawn for a play, a region, or for the entire Devonian system.

Economic potential is measured for both full-cycle and half-cycle cases. the full-cycle base includes all exploration, development, and production costs, including overheads, but excluding land acquisition costs. This definition is consistent with the practice of estimating prospect profitability prior to making expenditures for land. The half-cycle case excludes all pre-development costs.

The full-cycle and half-cycle analyses are undertaken in both fiscally burdened and unburdened contexts. The burdened analysis includes net taxes and royalties, and is relevant to private sector investment decisions. The unburdened analysis excludes fiscal burden, and is, therefore, relevant to public sector resource management.

SCOPE OF THE STUDY

Total gas resources in the Devonian system of the WCSB are estimated to be 3,528 billion cu m (126 tcf).

About 1,959 billion cu m (70 tcf), or 56% of the total resource remains to be discovered, of which 564 billion cu m (20 tcf) is estimated to be found in mature plays and 1,345 billion cu m (50 tcf) in conceptual plays.

Economic analysis is limited to the 25 mature plays for which undiscovered pool size estimates and supporting geological information are available. Since pool size distributions and related geological information are not available for conceptual plan,s, results of the economic analysis for the mature plan,s have been extended to conceptual plays in order to provide some estimate of their economic potential.

METHODOLOGY

The resource assessment is undertaken at the play level. Project economics is used to estimate the supply price of each undiscovered pool in the play. This approach allows for the consistent treatment of geological, engineering, and economic factors at the play level.

Basic inputs in the methodology used to estimate supply prices and construct supply curves are the estimated size of an undiscovered pool in a play, together with associated geological and reservoir parameters from the regional geology (Fig. 1). The expected exploration, development, and production costs for a selected pool are estimated, as well as the expected production profile. These are provided as inputs to subsequent discounted cash flow analysis.

An initial supply price of natural gas is used to estimate gross revenue from natural gas and co-product sales. Royalty and taxes are calculated and net cash flow is estimated. The price is varied until the calculated rate-of-return is equal to the minimum required rate-of-return.

The supply price is estimated for each pool in the undiscovered pool array, to a maximum price of $300/thousand cu m ($8.50/Mcf) in 1990 dollars. Supply curves are then constructed from these supply prices.

For most plays, natural gas is found primarily as either nonassociated gas or as solution gas. In some plays, however, significant quantities of natural gas may be found in both forms. Further, natural gas found may either be sour or sweet, i.e. it may or may not contain hydrogen sulphide (H2S)

For those plays in which significant quantities of natural gas are found as both nonassociated and solution gas, or as sour and sweet gas, a weighted average supply price is calculated, using as weights, the fractions of the resource base having the given attributes.

As mentioned above, supply curves are prepared for full-cycle and half-cycle economic potential, in both the burdened and unburdened contexts. For each of the four cases, two measures of long-term economic potential are provided. These are (a) the volume of economically recoverable gas-in-place (GIP), and (b) the volume of economically recoverable GIP as a percentage of the total technically recoverable GIP.

Sensitivities of the economic potential to key input parameters are also prepared. Estimates of the number of pools which are economic at given prices are provided.

TECHNOLOGY, COSTS

The exploration, development, and production requirements for natural gas pools and the associated costs depend on the geological characteristics of the pool, such as the original-gas-in-place, pool area, pool depth, drilling success rates, gas composition, and production rates.

The engineering and costing model constructed to support the economic analysis captures the impact of these factors, and allows for economies of scale and discontinuities in development and production costs over the full range of estimated undiscovered pool sizes.

Costs: Table 1 lists the capital and operating cost components used to estimate the costs of finding, developing, and producing non-associated gas pools. Wherever possible, the estimated relationships are play specific and are based on industry experience and practices. Regional cost differences are captured by assigning each play to one of five cost areas used in the study (Northwest Alberta, Peace River, West-Central Alberta, Southwest Alberta, or Northeast British Columbia).

Details regarding the model, inputs and associated cost estimates are provided in GSC Bulletin 452 and GSC Open File Report 2673.

In the economic analysis of solution gas production, all exploration costs and many development costs are assumed to be already spent on the search for, development and production of crude oil pools. Local dehydration and compression at the oil battery and a raw gas transmission line to the local processing facility are considered to be the only cost components relevant to an incremental investment decision to recover solution gas.

Production profiles: For nonassociated gas, the raw gas production profile is defined by assigning the pool to one of five size classes, depending upon the volume of recoverable GIP. A typical production profile consists of an initial period at a constant production rate, followed by a period of production on exponential decline.

It is assumed that 50% of the recoverable gas is produced during the period of constant production. The time periods for constant and declining production are chosen to reflect accelerated production usually associated with smaller reservoirs. The size classes and parameters for each class are listed in Table 2.

For solution gas reservoirs, production profiles assume a constant gas-oil ratio and a constant remaining-oil-reserves-to-production (R/P) ratio of 10.

In both cases, the raw gas production profiles are converted to sales gas and co-product production profiles.

ECONOMIC INPUTS

Major economic assumptions used in this study are as follows:

Fiscal system: The Canadian federal and provincial (Alberta and British Columbia) fiscal regimes in place as of January 1992 are used in the determination of taxable and net income. All companies are assumed to be fully taxable and, therefore, able to claim all deductions in the same year they become available.

Inflation rate: Application of the fiscal system requires conversion of all real costs into current values using an assumed rate of inflation. The inflation rate is assumed to be 4%/year. Inflation is subsequently removed from the estimates in order to calculate supply prices in constant 1990 dollars.

Use of economic success rate: The number of exploratory wells required for each pool is estimated using economic success rates as opposed to technical success rates. The economic success rate is measured as the ratio of economic pools to the number of exploratory tests.

Economic pools are defined as those pools that earn an after-tay real rate-of-return of at least 10% at a plant gate price of $88.25/thousand cu m (52.50/Mcf), on a half-cycle basis.

Co-product prices: Co-product prices are estimated as a function of the price of natural gas or crude oil, using historical correlations.

Expected rate-of-return: The expected real minimum after-tax and royalty rate-of-return is assumed to be 10%. The same rate is used for the burdened and unburdened cases to facilitate comparison,

MATURE PLAYS POTENTIAL

Economic potential has been estimated for a reference case using the mean resource estimate for each undiscovered pool.

The reference case assumes (a) the same geological characteristics (e.g., depth) for individual pools as the play average, (b) average costs, (c) play-specific economic exploration success rates, (d) an average distance to the gas pipeline network based on the current infrastructure, and (e) the same proportions of non-associated and solution gas, and sweet and sour gas, as resources currently discovered for the play. Costs and supply prices are estimated in 1990 dollars.

The reference case is based on data available at the time of the analysis. It does not consider improvements in economic success rates due to increased knowledge of exploration plays, reductions in development costs due to expansions of pipeline networks, or possible decreases in costs due to technological changes and improvements in company practices. Consequently economic potential for the reference case should be considered closer to the current economics of exploration. It is likely a downward biased estimate of long-term exploration fundamentals.

Figs. 2 and 3 present the burdened full-cycle and half-cycle supply curves for the mature Devonian plays. Fig. 2 shows the volume of economically recoverable GIP, while Fig 3 shows the volume of economically recoverable GIP as a percentage of total recoverable GIP. (Similar curves for the unburdened case are found in Bulletin 452).

While supply curves prepared for this study provide prices ranging to $300/thousand cu m ($8.50/Mcf), a more realistic range for prices is $35-106/thousand cu m ($1-3/Mcf). The bounds of this price range are shown with broken lines on each figure.

For discussion purposes, results are referenced at two prices: $44.13/thousand cu m ($1.25/Mcf), representing plant-gate prices at the time of analysis, and $88.25/thousand cu m ($2.50/Mcf) reflecting long-term price expectations. (Tables showing the estimates of economic potential at these two prices, for all four cases examined in this study can be found in GSC Bulletin 452.)

Major conclusions with regard to economic potential are:

• Economic potential is estimated to be 68 billion cu m (2.4 tcf), or approximately 1617( of the total recoverable GIP, on a burdened full-cycle basis at $44.13/thousand cu m. Economic potential increases to 180 billion cu m (6.4 tcf) or 43% of the total recoverable GIP, at a price of $88.23/thousand cu m.

• As expected, economic potential is significantly higher for the half-cycle case than for the full-cycle case. At $44.13/thousand cu m economic potential in the burdened half-cycle case is estimated to be 45% of the recoverable GIP, while at $88.25/thousand cu m, 75% is economic. (While pools that are economic solely on a half-cycle basis are not exploration targets, they are usually booked as reserves with provincial regulatory bodies if discovered.)

• There is little difference between burdened and unburdened economic potential.

  This suggests that the existing federal and provincial fiscal regimes do not significantly reduce the profitability of finding and developing marginally economic resources. (The result does not imply, however, that more profitable investments are not paving significant taxes and royalties, or that activity would not be stimulated by a reduction in fiscal burden.)

• The supply curves aye elastic in the price range of $17.65-88.25/thousand cu m (50-$2.50/Mcf). That is, a given percentage increase in supply price within this range leads to a more than proportional increase in economic potential. Above a price of $88.25/thousand cu m, the supply curve is relatively inelastic.

SENSITIVITY ANALYSIS

Significant variability and uncertainty surround estimates of costs, exploration drilling success rates and the distance of discoveries to gathering systems.

The impact of changes in these factors on economic potential is examined through sensitivity analyses. The changes examined are:

• Costs 20% above and 30% below the reference case

• Doubling of the economic success rate used in the reference case, and

• Reduction of average distance of pools to a gathering system to 2.5 km for all plays.

  In general, the relative impact of these chances on economic potential is larger at lower prices and smaller at higher prices, due to the skewed distribution of the resources toward smaller pools. Hence results for these sensitivities are summarized at a price of $44.13/,thousand cu m ($1.25/Mcf), as follows:

• An increase in costs of 20% or a decrease in costs of 30% reduces/increases total economic potential in the burdened full-cycle case by 10%, relative to the reference case.

• Doubling economic success rates for all plays increases total economic potential in the burdened full-cycle case by 38%.

• Reduction in the average distance of pools to a gathering system to 2.5 km for all plan,s increases economic potential by about 16% in both the burdened full-cycle and half-cycle cases.

CONCEPTUAL PLAYS

Approximately 70% of the undiscovered gas resource in the Devonian system is estimated to exist in conceptual plays. Detailed geological characteristics of these plays are unknown, and consequently estimating costs of exploration, development and production would be speculative.

The economic potential of these resources is, therefore, estimated by extrapolating the results for mature plays, described above, to the resources estimated to exist in conceptual plays. This is accomplished by applying the proportion of economic potential to total recoverable GIP for mature plays to the total estimated recoverable GIP for conceptual plays. The technical recovery factor for conceptual plays is assumed to be 73%.

Fig. 4 shows the economic potential for the entire Devonian system, including conceptual plays. At the long-term price of $88.25/thousand cu m ($2.50/Mcf), the total burdened full-cycle economic potential, including resources in conceptual plays, increases to 634 billion cu m (22.5 tcf).

NO. OF ECONOMIC POOLS

While estimates of economic potential are the primary objective of this work, a better measure of prospectivity is the number of pools that would be economic to find, develop, and produce, at a given price.

Fig. 5 shows the number of economic pools (for the burdened, full-cycle case) under different price assumptions. Each curve terminates at the marginal pool sizes for that price.

Major observations regarding the number of pools are as follows:

• The undiscovered resource is estimated to exist in more than 6,800 pools greater than 1 million cu m. The vast majority of these undiscovered pools, however, are too small to be viable exploration targets.

• At $106/thousand cu m ($3/MCF), 435 pools greater than 50 million cu m (1.8 bcf) are expected to be economic in the burdened, full-cycle case.

• At $35/thousand cu m ($I/Mcf), the minimum pool size that would be economic is 265 million cu m (9.5 bcf). As expected, given that there are relatively fewer pools at the larger pool sizes, the number of viable exploration targets is significantly reduced to 35.

CONCLUSION

The study shows that there remain significant volumes of economically recoverable resources to be discovered in the Devonian system of the WCSB, even at prices as low as $44.13/1,000 cu m ($1.25/Mcf).

Since a consensus of forecasts expects much higher gas prices in the long-term, the Devonian system of the WCSB can be expected to offer attractive exploration opportunities. This conclusion is reinforced by the fact that estimates of costs and assumptions regarding the introduction of technological improvements are conservative, and likely, therefore, result in an underestimate of the long-term economic potential.

ACKNOWLEDGMENTS

This work was undertaken by the Petroleum Resource Appraisal Panel (PRAP), a joint organization of the Geological Survey of Canada and the Energy sectors of Energy, Mines and Resources Canada. The GSC is responsible for the regional geology and resource assessment, and the Energy Sector for the complementary economic analysis. The authors thank the PRAP management committee for permission to publish this paper. We also thank Louise Roux and Myriam Boudreault of the Petroleum Resource Analysis Section, who conducted the analytical work for the study, and Dr. P.J. Lee of the GSC for his assistance in interpreting the assessment information.

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