Performance Review of Brazeau River Nisku Dry-Gas Miscible-Flood Projects
- Jong I. Lee (Petro-Canada Resources) | Ernesto L. Astete (Astete Enterprises) | Tim F. Jerhoff (Petro-Canada Resources)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Engineering
- Publication Date
- February 1994
- Document Type
- Journal Paper
- 29 - 34
- 1994. Society of Petroleum Engineers
- 5.2.2 Fluid Modeling, Equations of State, 5.1 Reservoir Characterisation, 5.2.1 Phase Behavior and PVT Measurements, 4.2 Pipelines, Flowlines and Risers, 5.7.2 Recovery Factors, 5.4.2 Gas Injection Methods, 5.4.9 Miscible Methods, 5.4.1 Waterflooding, 1.6 Drilling Operations, 4.6 Natural Gas, 1.14 Casing and Cementing, 5.6.9 Production Forecasting
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This paper reviews 10 years of dry-gas miscible-flood operations in three Brazeau River Nisku pinnacle reefs in Alberta. In addition, actual pool performance is compared with the original black-oil-model simulation forecasts. Through June 1991, the pools recovered 50% to 70% of original oil in place (OOIP), exceeding estimated waterflood recovery for each pool. Ultimate recoveries are expected to be 60% to 80% of OOIP, the range original predicted.
The Brazeau River Nisku field is ˜155 km southwest of Edmonton, Alta. (Fig. 1). Field development began in Jan. 1978, when Well 11-31-48-12 W5M was drilled into Nisku Pool A. Nisku Pool D was discovered in June 1978 with the drilling of Well 7-33-48-12 W5M, and Nisku Pool E was discovered with the drilling of Well 2-26-48-13 W5M in July 1978. Subsequently, between 1978 and 1982, three sour-gas-condensate pools, Pools F, M, and P, and a sour-oil pool, Pool L, were discovered. Fig. 2 shows the locations of the Nisku pools.
Pools A, D, and E are sweet-oil reservoirs containing light, volatile oil with an 800-kg/m3 density. Solution GOR's range from 140 to 420 m3/m3, average porosities range from 7% to 10%, and net pays are between 40 and 80 m. Average pool permeabilities vary from 50 to 330 md. Pool E is associated with an inactive bottom aquifer. Pools A and E were overpressured reservoirs, with initial pressures >46×103 kPa. Table 1 summarizes the oil compositions, and Table 2 lists the reservoir parameters. All three pools produced under a primary production scheme until bubblepoint pressure was reached, after which a dry-gas miscible flood was begun. Miscible flooding was chosen for these oil pools because of gas availability, reservoir quality, and a governmental royalty-relief incentive program.
The Nisku reefs are of the Upper Devonian Winterburn group at a 3200-m depth. The reef base covers approximately one section (256 ha) in areal extent. The reefs are almost entirely dolomitized, with Pools A and E containing moldic vuggy pores. In Pool D, porosity and permeability are reduced by complete or partial plugging of both intercrystalline and moldic vuggy pores owing to sparry calcite cement.
Primary facies and diagenetic modifications of the reefs vary widely; therefore, reservoir properties are difficult to correlate between wells. The net/gross oil-pay ratios vary between 0.5 and 0.8.
Miscibility conditions were determined by slim-tube tests and a phase diagram constructed with an equation of state. The Alberta Energy Resources Conservation Board (AERCB) approved the miscible-flood projects under the condition of a minimum 10 mol% ethane-plus concentration in the injection gas at the specific operating pressure for each pool.1-3 Table 3 presents the pool miscibility pressures and the AERCB-approved operating pressures. Operating pressures were set ˜1000 to 1500 kPa above the minimum miscibility pressure to provide a safety factor for miscible-flood operation. During the 10 years of operation described here, the ethane-plus concentration of the injection gas has been 12 to 15 mol% and reservoir pressures have been maintained above the approved operating pressure for each pool. Table 4 shows the injection gas composition.
The structurally highest well in each pool was chosen as the injector to maximize oil displacement under the vertical miscible floods. The producing wells were completed at the lowest porous interval in Pools A and D and 8 to 10 m above the oil/water contact (OWC) in Pool E.
Reservoir model studies were conducted with a black-oil simulator to predict pool performance under both miscible-gas and waterflood depletion schemes. Coning model studies were conducted to investigate near-wellbore gas and water coning phenomena. Cross-sectional model studies investigated the overall sweep efficiency of each depletion scheme. Combining the coning and cross-sectional model results generated overall pool production forecasts.4 Predicted miscible-flood recoveries were from 60% to 80%, exceeding waterflood recoveries by 15% to 25%.
Pool A is the largest of the three oil pools, with 5300×103 m3 OOIP. Pool A consists of two producers, Wells 15-31 and 11-31, and one injector, Well 5-6. The pool produced under a primary production scheme until Sept. 1980, when gas injection began. Cumulative oil production to this time was 6% OOIP. The pool continued to produce at primary rates while gas was overinjected to repressure the pool to 36×103 kPa, the AERCB-approved operating pressure. By April 1982, the pool had been repressured and the voidage replacement ratio has been maintained above unity since. Fig. 3 shows Pool A pressure history.
Fig. 4 shows that pool oil production was 1200 m3/d from 1982 through 1988. Oil production has been limited by the pool's share of the gas-plant capacity when excessive gas production has occurred. Gas broke through in both producers in mid-1988 at a recovery factor of 60% OOIP. Fig. 5 shows a structural cross section of Pool A. The estimated gas/oil contact (GOC) at gas breakthrough was ˜20 m above the top of the producing perforations. The approximate location of the GOC was determined by a material balance. More exact methods, such as thermal-decay-time logging, were attempted but were unsuccessful. In 1989, the top completion interval of Well 11-31 was cement squeezed in an effort to control increasing GOR.
Currently, the pool is producing 400 m3/d of oil with a GOR of 1800 m3/m3. The recovery factor through June 1991 is 70% OOIP, and the current estimated GOC is ˜10 m above the top of the perforations. Fig. 6 compares the overall GOR behavior of the pool with the original simulation forecast and shows an excellent match. The original forecast indicates a 75% pool recovery at the economic 2000-m3/m3 GOR limit, which matches well with the current estimate of 72% at the economic limit. Ultimate recovery for the pool, including the blowdown phase, is expected to approach 80% OOIP.
Pool D contains four wells; three producers, Wells 15-28, 7-33, and 5-34, and an injector, Well 10-33. Fig. 5 shows the outline and a cross-sectional view of Pool D. The material balance calculations based on the primary production and pressure data resulted in a 2700×103 m3 OOIP.
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