Previous estimates of the aggregate potential for increasing oil recovery from existing reservoirs have focused on either broad geological horizons or on a few of the larger existing reservoirs. This study evaluates reservoirs of all sizes using individual development patterns within each reservoir as the basic analytical unit. The procedure yields results that fall within the range of previous estimates. However, the indicated profitability of many small pools that are normally excluded from consideration in aggregate analyses suggests that ome reconsideration of these "mini" opportunities may be in order.

Alberta Energy Resources Conservation Board data on reservoirs was screened using procedures developed by the Petroleum Recovery Institute to sort the reservoirs according to the recovery processes that may be technically feasible. The processes considered were steam drive, steam stimulation, in situ combustion, polymer augmented waterflood, alkaline flood, microemulsion flood, CO2 miscible, and hydrocarbon miscible. Recovery models specific to each process were applied to all reservoirs that emerged from the screening procedure to estimate incremental recovery and a likely time profile of production.

Economic viability was investigated with and without tax and royalty considerations for each reservoir to provide some insight into the potential impact of fiscal incentives on ultimate recovery and rates of production. Results by reservoir were then aggregated to determine overall provincial potential. The economic analysis also developed the price per barrel (supply price) required to recover all costs of development and operations for each reservoir.

Equation (Available in Full Paper)

Production rates (q) and recoverable oil (R) depend on costs (TC), in particular on well spacing and in tertiary development on the quantity and cost of injected materials. If the relations among R and TC are known, (1) may be solved to yield optimal investment and production profiles and project life.

Unfortunately technological uncertainties of tertiary processes and uncertainty regarding individual reservoir characteristics preclude the formal use of (1). An alternate procedure within this general framework involves specification of assumed optimal values for TC, q, R, and T followed by evaluation of economic viability. In other words, instead of choosing the economically optimal path from a number of alternatives, we specify an assumed optimum path and determine whether or not it is economically viable. This is done for each reservoir that is deemed technically amenable to tertiary operations (see section 1.2.l). The results are then aggregated to provide recovery estimates by process, with and without tax and royalty consideration, for the province of Alberta.1.

1.2 Models of Production and Economics

The potential of eight tertiary recovery processes listed below is developed.

  • Thermal Processes

  • steam drive

  • steam stimulation

  • in situ combustion

  • Chemical Processes

  • Polymer augmented waterflood

  • alkaline flood

  • microemulsion flood

  • Miscible Processes

  • hydrocarbon miscible

  • Carbon dioxide miscible

1.2.1 The Data Base

The analysis is tested on the ERCG annual reserves report for 1975. All reservoir listed were passed through a technical screening procedure developed by the Petroleum Recovery Institute. Reservoir meeting the screening requirements were allocated to one or more of the tertiary processes.

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