Connacher's first oil sands project, the Pod One facility at Great Divide, has been operational since 2007. The successful SAGD project has produced approximately 7 million barrels of bitumen. During the past three and a half years, the impacts of certain predicted reservoir challenges and opportunities have become apparent.
While the quality of the oil sands in this first phase of Pod One is generally good, Pad 101 South in particular has geological zones that affect SAGD operation. This includes a bitumen lean zone, and a gas cap overlying the main bitumen channel/s. Early field results matched with detailed simulations have shown positive results in maximizing well pair production. For the purposes of this paper a lean bitumen zone differs from an aquifer in two ways. The lean zone is not charged, and is limited in size. The operation is also complicated by the fact the gas bearing zone has been depleted through earlier production.
Connacher's operating practice at Great Divide attempts to achieve a pressure balance between the 3 zones (rich oil sands, lean zone, gas cap) to reduce steam loss and maximize production rates. Reducing the pressure encourages steam chamber development growth horizontally and ensures that steam contacts the highly saturated bitumen areas. How this is achieved with the highest positive impact on well productivity is illustrated with operational data and analysis including the results of simulations that recommended the optimum operating strategies.
Ground deformation was monitored for nearly ten weeks during the first cycle of steam stimulation in a single-well test using an array of high-resolution borehole tiltmeters. The test was conducted in a section of the Athabasca oil sands having properties similar to the unconsolidated oil sands of California. The properties similar to the unconsolidated oil sands of California. The 310 meter injection depth was also comparable to the depth of thermal stimulation in many California oil fields. Ground response indicated that steam injection was not a continuous process, but rather was characterized by numerous episodic events. During these events wellhead pressure dropped (in one case by 2650 kPa), boiler feed rate increased by a few percent, and the ground surface within the instrument array was lifted percent, and the ground surface within the instrument array was lifted up. Pressures again began to rise and the ground surface subsided within a few hours of the beginning of an event, but subsidence always preceded pressure increase. The magnitudes of the pressure and deformation changes pressure increase. The magnitudes of the pressure and deformation changes varied from event to event, apparently unsystematically.
The events are interpreted to have resulted from breakdown of the oil sands and attendant propagation of hydraulic fractures away from the wellbore in approximately horizontal planes. Larger fractures may have continued to propagate until internal pressures were insufficient to lift the overburden, at which time they collapsed. Fracture growth terminated at higher pressures in events for which deformation changes were small, perhaps because of inelastic blunting of the fracture tips. Modelling suggests that the radii of fractures formed in the larger events may have been about 160 meters, whereas those formed in the smallest events had radii of about 40 meters.
A delay of three weeks between the start of steam injection and the occurrence of the first episodic event suggests that there may have been major modification of the in-situ stress state during this period. Pressure records from cold-water hydraulic fracturing a week before the Pressure records from cold-water hydraulic fracturing a week before the start of steam injection indicate that this fracture was vertical, from which we infer that the most compressive component of in-situ stress was also vertical. Gradual heating of the oil sands during steam injection should have closed the vertical fracture by thermal expansion, and then led to an increase of horizontal compression as further lateral expansion was suppressed. Formation of horizontal fractures after three weeks of steaming is consistent with a modified in-situ stress state in which horizontal exceeded vertical compression.
During the months of July, August and September 1979 Gulf Canada Resources Inc. conducted the initial cycle of steam stimulation and production in a single well approximately 50 km south-southeast of Fort McMurray, in the Athabasca oil sands region. The well is located in land survey 11, section 20, township 83, range 6, west 4th meridian. This project comprised the initial stage of Gulf's first single-well test on the lease, and was followed by additional cycles of steam injection and production. Part of the study of the initial steam stimulation cycle consisted of precision monitoring of ground deformation around the well, produced by reservoir response to steam injection. Deformation monitoring was conducted to obtain direct measurements of the physical responses produced by steam stimulation in order to better characterize reservoir processes and to obtain data for comparison with theoretical models of reservoir behavior. One important objective was to obtain an estimate of the dimensions of the thermally stimulated volume of oil sands. This paper describes the results of the monitoring program and offers interpretations of the behavior that was observed.
GEOLOGY OF THE TEST SITE
The oil sands that were the target of the single-well test are in the Cretaceous McMurray Formation. Rich oil sands occur between the depths of 308m and 317m in the well.