Review of Phase A Steam-Assisted Gravity-Drainage Test
- N.R. Edmunds (Alberta Oil Sands Technology & Research Authority) | J.A. Kovalsky (Alberta Oil Sands Technology & Research Authority) | S.D. Gittins (Alberta Oil Sands Technology & Research Authority) | E.D. Pennacchioli (Alberta Oil Sands Technology & Research Authority)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Engineering
- Publication Date
- May 1994
- Document Type
- Journal Paper
- 119 - 124
- 1994. Society of Petroleum Engineers
- 5.3.9 Steam Assisted Gravity Drainage, 1.6 Drilling Operations, 5.3.2 Multiphase Flow, 3 Production and Well Operations, 4.2 Pipelines, Flowlines and Risers, 4.3.4 Scale, 2.4.3 Sand/Solids Control, 5.6.9 Production Forecasting, 5.5.8 History Matching, 5.1.1 Exploration, Development, Structural Geology, 1.6.6 Directional Drilling, 1.7.5 Well Control, 5.8.5 Oil Sand, Oil Shale, Bitumen, 1.2 Wellbore Design, 4.1.5 Processing Equipment, 4.2.4 Risers, 5.2.1 Phase Behavior and PVT Measurements, 4.1.2 Separation and Treating, 3.3.3 Downhole and Wellsite Flow Metering, 5.1 Reservoir Characterisation, 5.4.6 Thermal Methods
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This paper presents a case history of the Phase A steam-assisted gravity-drainage (SAGD) test conducted by the Alberta Oil Sands Technology & Research Authority (AOSTRA) at its underground test facility (UTF). Reservoir description, the recovery process, design of wells and other critical hardware, production operations history, and performance analysis are discussed. Phase A demonstrated a commercially viable combination of recovery, production rate, and steam/oil ratio (SOR). Completions design and production engineering progressed significantly. Phase B scaleup considerations and commercial economic projections also are discussed.
The Athabasca oil sands of northern Alberta, Canada, are sometimes referred to as the greatest single accumulation of petroleum in the world. These sands are estimated to contain ˜ 1050 kg/m3 of bitumen. About 90% of this resource is buried too deeply to be recovered by mining and will require in-situ recovery methods. A number of pilot projects testing a wide array of potential technologies have been carried out over the past 60 years, but few have met with much technical success and none has been expanded to commercial production to date.
The AOSTRA UTF is 40 km northwest of Fort McMurray, Alta. The facility was constructed during 1985-87 and consists of two l85-m vertical shafts and > 1 km of underground tunnels driven into Devonian limestone that immediately underlies the McMurray formation. The 5-m-wide by 4-m-high tunnels are ˜ 15 m below the reservoir. Wells are drilled upward from the tunnels, starting at 15 to 20° angles above horizontal, then dropping to horizontal in the oil sand.
Steam generation and production-handling facilities are on the surface. Production testing of individual wells was carried out undergroundby means of a Coriolis mass flowmeter and careful wellhead sampling. Ref. 1 gives a more complete review of the UTF history and physical plant.1
The first process selected for testing at the UTF was SAGD. SAGD is a combined conduction/convection mechanism that is more like ablation (i.e., propagation of a melt front into a solid material) than displacement, which is the usual petroleum engineering paradigm for thermal recovery.
Fig. 1 shows that conduction heats a thin layer of oil sand adjacent to the steam "chamber," mobilizing the bitumen. The density difference between the steam and bitumen causes the bitumen to drain to the bottom of the chamber along with the steam condensate that is formed as a result of the heat conduction ahead of the front. The steam gains access to new formation as the bitumen drains, causing the front to advance upward and outward. This continues as long as more steam and oil sand are available and as long as the draining bitumen and condensate are removed from the bottom of the chamber. The rate of drainage is controlled by permeability.
Liquids within the steam chamber drain very rapidly relative to the speed of frontal advance so that chamber gas saturations are high and the water and oil saturations are close to residual values. Cumulative oil production is nearly proportional to the steam-chamber volume. Refs. 2 through 4 provide a more complete discussion of SAGD mechanisms.
The Phase A Test.
Regardless of well control and petrophysical data available, the extreme heterogeneity of the McMurray pay makes a priori forecasting of SAGD performance problematic because interbedded sand lenses can form tortuous but continuous paths that are not discernible from delineation wells. The main objective of the Phase A test was to resolve this uncertainty by direct measurement of the SAGD rate in a minimal volume of reservoir. Phase A consisted of three pairs of horizontal wells (Fig. 2). Each well pair had a producer completed low in the pay zone and an injector parallel to and ˜5 m above the producer. The well pairs were nominally spaced 25 m apart, and the effective length of the completions was 55 m. The pattern also contained 26 temperature, pressure, and geotechnical observation wells drilled vertically from surface.
Ref. 5 describes the geology of the Phase A site. Fig. 3 is a cross section through the middle of the pilot, and Table 1 lists some key petrophysical parameters for the UTF site that are typical of the McMurray formation throughout the Athabasca region.
Units E and G, comprising most of the bottom half of the pay, were high-quality, essentially continuous sand bodies that were highly saturated with bitumen. The top half of the pay, Unit D, was interbedded and bioturbated sand, silt, and claystones. The sand lenses were all well-saturated.
Unit F consisted of muds and silts that were interbedded with sand lenses and heavily bioturbated. This unit separated the injectors and producers for two of the well pairs, Pairs Al and A3. The other pair, Pair A2, was deliberately drilled so that both wells were above this partial barrier.
At the cold initial reservoir temperature (7°C), bitumen is extremely viscous and connate water is immobile. Mobility in the reservoir is so low that superficial oil-phase velocities can be measured in feet per year, even under huge pressure gradients. This precludes direct convective heating as in a classic steamflood displacement.
Completions design6 was considered critical to the success of the Phase A test. Massive sand influx into the wellbore had been encountered by previous operators in the region and was considered the most likely cause of possible test failure. In addition, the liners had to be large enough to prevent large pressure gradients, especially in the injection well, because excessive pressure gradients in the wells also appear in the steam chamber and interfere with gravity stabilization of drainage over the length of a well pair.7
All wells were completed with l4-cm liners, made up of alternating sections of blank casing and sand control screens, run into open hole (Fig. 4). Conventional wire-wrapped screens were used in two well pairs, and a steel-wool-filter design was used in the third pair. Tubing strings were landed near the end of each liner to provide circulation of hot fluids throughout the length of each well.
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