Underground Test Facility: Shaft and Tunnel Laboratory for Horizontal Well Technology (includes associated papers 17469 and 17654 )
- D.A. Best (The Alberta Oil Sands Technology and Research Authority) | G.M. Cordell (The Alberta Oil Sands Technology and Research Authority) | J.A. Haston (The Alberta Oil Sands Technology and Research Authority)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- May 1987
- Document Type
- Journal Paper
- 603 - 612
- 1987. Society of Petroleum Engineers
- 5.6.4 Drillstem/Well Testing, 4.6 Natural Gas, 1.11 Drilling Fluids and Materials, 5.5 Reservoir Simulation, 5.8.5 Oil Sand, Oil Shale, Bitumen, 2 Well Completion, 2.4.3 Sand/Solids Control, 1.6 Drilling Operations, 6.5.5 Oil and Chemical Spills, 1.14 Casing and Cementing, 3 Production and Well Operations, 5.4.6 Thermal Methods, 1.6.6 Directional Drilling, 4.3.4 Scale, 1.6.9 Coring, Fishing, 4.1.5 Processing Equipment, 5.2 Reservoir Fluid Dynamics, 4.1.2 Separation and Treating, 1.6.2 Technical Limit Drilling, 5.7.2 Recovery Factors, 1.14.1 Casing Design, 5.1.5 Geologic Modeling, 5.4.2 Gas Injection Methods
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The Alberta Oil Sands Technology and Research Authority has initiated an extensive, long term program to evaluate horizontal well recovery processes in a shaft and tunnel complex in the Athabasca tar sands, 35 miles NW of Fort McMurray, Alberta.
The 213 m twin shafts, the initial pit bottom, tunnel development and the surface mine support equipment have been contracted. Shaft sinking started February 1985. Shaft No. 1 took 55 days to drill; No. 2 took 46 days. The access facilities are scheduled to be operational March 1986. Mine extension and pilot startup will be completed by mid '87, pilot startup will be completed by mid '87, after which horizontal well drilling/completion technology and a variety of recovery strategies will be evaluated.
The commercial economics of the shaft and tunnel concept for bitumen recovery from the Athabasca tar sands will also be firmed up during this period. Initial feasibility studies were positive for this reservoir with 15 km of tunnel and 356 horizontal wells over the project life. Preliminary designs for well project life. Preliminary designs for well completion and process service facilities have been based on a steam recovery process. Ultimate production capacity is intended to be 1,600 m3/day or 10,000 BPD.
HORIZONTAL RECOVERY PROCESSES
Theory and experience teaches that mobility ratios dominate volumetric sweep efficiency of a reservoir. The bitumens in the Alberta tar sands are so viscous that, if this experience holds for these reservoirs, heating to several hundred degrees would produce little improvement in overall volumetric recovery efficiency. Yet two of the current in situ tarsands projects that are expanding to commercial levels Shell's Peace River project and Esso's Cold Lake project - are reporting recoveries in excess of 20%, and in the case of the Shell Project, estimates of volumetric sweep Project, estimates of volumetric sweep efficiency indicate +50% possible. Clearly the inconsistency between theory and practice lies not with the reported performance of the field projects but with the theory. Gravity drainage projects but with the theory. Gravity drainage is one factor that plays a considerable role.
At Shell's Peace River pilot a pressure cycling strategy is used. Steam is injected into a thin transition zone at the base of the reservoir. The steam rises and heats the bitumen which drains downward toward this higher permeability, water saturated zone. The hot oil permeability, water saturated zone. The hot oil is produced during the drawdown cycle. The excellent areal conformance of the steam through this bottom water zone combined with the improved vertical conformance caused by the downward movement of the mobilized bitumen appears to be the rational for the excellent recoveries already obtained after only several cycles of pilot operation.
With Esso's Cold Lake pilot, vertical fractures are created to achieve the requisite injectivity of steam for their steam stimulation operations. The lack of native injectivity confines the steam to the near-fracture region. Efficient flowback of the confined steam appears to be a dominant driving force for producing the heated bitumen. Gravity also plays a part. The heated bitumen can drain downward in the region of the fracture, allowing for further extension of the steam heated zone away from the fracture plane. plane.
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