American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. This paper was prepared for the Rocky Mountain Regional Meeting of the Society of Petroleum Engineers of AIME, to be held in Billings, Mont., May 15–16, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Summary Reservoir simulation studies were conducted on selected reservoirs to establish the relationship between ultimate recovery and reservoir withdrawal rate. The rates ranged from far above to far below normal production practice. The simulation results indicate that for each reservoir and each development plan an MER curve, a curve of ultimate recovery versus reservoir withdrawal rate, can be determined given the necessary data. These curves show varying, but often pronounced, increases in ultimate recovery as withdrawal rate decreases. The sensitivity of ultimate recovery to production rate may be affected to varying degrees by well spacing, well completion practices, fluid properties, reservoir heterogeneities, reservoir type and exploitation scheme. Results of studies on some of the parameters are presented. Introduction Conservation in the oil and gas industry dates back to the late eighteen hundreds and historically has dealt with the prevention of "reasonably avoidable waste of oil and gas". Legislators and conservation officials have conceived numerous means of regulating this concept. In a comprehensive review and discussion of conservation efforts by members of the Interstate Oil Compact Commission (IOCC) in 1965, it was found that the concept of MER (Maximum Efficient Rate) was a predominant method of preventing avoidable waste of oil and gas. In 1971 the federal government announced its intention to adopt MER as a means of regulating production on the outer continental shelf and in 1974 format production on the outer continental shelf and in 1974 format regulation by MER will be initiated in the form of OCS Order Number 11 which adopts the following definition of MER: "the maximum sustainable daily oil and gas withdrawal rate from a reservoir which will permit economic development of that reservoir without detriment to ultimate recovery". It is to this definition of MER that this paper addresses itself.

ABSTl!ACTA two-dimensional mathematical model was formulated Lu describe the injection or steam into an oil reservoir assuming that a step-function satisfactorily approxintates the actual temperature pwfile within the I)ermeable sand. The model was applied to a homogeneous isotropic reser-,·oir tu calculate the temperature in the surrounding strat;.t and the thermal effit:ienc:r of the injection process. For a particular set of res1·n·oir conditions. the comparison of the results with a published analytical solution for the one-dimensional case showed that there exists a particular injection rate and par thickness below which the one-dimensional heat transfer model mav not be valid.A second model was formulated to describe the backflow period. The thermal behaviour of the non-permeable strata was accounted for by diYiding the surrounding formation into two sets of semi-infinite concentric cylinders and olppl}'ing the om~-dimensional heat flow equation to each shelL The fluid mechanics aspect was described by applring Darcy's equation under plug-fh1id flow conditions. With the exception of viscosity, all physical propcrtie~ were assumed to be independent of temperature and were calculated at an a\·erage temperature.

Black-oil and multicomponent compositional models were used to simulate a gas-cycling scheme. Reservoir fluid sample data were carefully matched to ensure realistic predictions of phase behavior during cycling. The study indicated that cycling was technically feasible and that an additional 64,906,000 bbl of hydrocarbon liquid would be recovered over the life of the cycling and blowdown. Introduction The Bonnie Glen D-3A pool, discovered in Jan. 1952, is situated approximately 43 miles southwest of Edmonton, Alta. The reservoir, which forms part of the prolific Leduc reef chain, is one of the most capable prolific Leduc reef chain, is one of the most capable producing fields in Canada. The original oil in place producing fields in Canada. The original oil in place is estimated to be 657,138,000 STB, with an original gas cap of 444,900 MMcf. The recovery mechanism is primarily gas cap expansion and natural water influx with excellent gravity segregation, which will effect an estimated recovery of 452,226,000 bbl of oil, or 68.8 percent of the original oil in place. Since simultaneous production of the gas cap during the life of the oil column could be detrimental to oil recovery, gas cap production would normally be deferred until depletion of the oil column. Gas cycling, however, can be carried on while the oil column is depleting, with a beneficial effect on the over-all recovery of hydrocarbon liquids. Reservoir Properties and Performance The Bonnie Glen pool is a dolomitized, biotherm reef in the Leduc member of the Upper Devonian Woodbend formation and is completely underlain by the Cooking Lake formation. The reef, which forms part of the Leduc D-3 reef trend, is approximately 7 miles long, 21/2 miles wide at the original oil/water contact and less than 1 mile wide at the original gas/oil contact, Maximum original net pay thickness of the reef is 701 ft, of which 402 ft is gas cap and 299 ft is oil column. The Cooking Lake formation is an active aquifer extensive in all directions except to the west, where it pinches out almost immediately. The aquifer is common to other oil- and gas-bearing accumulations in the same reef trend (Fig. 1), and interpool interference is evident by past pressure trends of the D-3 pools. Fig. 2 presents a structure contour map of the top of the pool, based on the gross reef section, and Table 1 presents a summary of important reservoir properties. The original composition of the gas cap and oil column is presented in Table 2. Since discovery of the field, 166 wells capable of production have been drilled, most of them on production have been drilled, most of them on 40-acre spacing. Currently, 58 wells produce the field allowable of approximately 40,000 BOPD. Cumulative production to Dec. 31, 1971, was 154,078,000 bbl of oil, 114,500 MMcf of solution gas, and 1,204,000 bbl of water. The reservoir pressure at datum has declined from the original 2,477 psi to a current 2,005 psi. Fig. 3 presents the production and reservoir pressure history of the Bonnie Glen pool, and Fig. 4 shows a transverse cross-section of pool, and Fig. 4 shows a transverse cross-section of the reservoir, illustrating original and current gas/oil and oil/water interfaces. Interfaces were calculated by a combination of material balance and a knowledge of cumulative reservoir pore volume as a function of reservoir depth. Calculations agreed very closely with semiannual field measurements. JPT P. 1285

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