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.
Small volume hydraulic fracture tests, defined as microfrac tests, are conducted to determine the in situ principal stresses in oil formations. Interpretation difficulties arise when the tests are conducted in relatively shallow, unconsolidated sands which are typical of the oil sand deposits in Alberta, Canada. Interpretation methods for such tests are outlined and their use is discussed. Three microfrac case histories in the Athabasca oil sands deposit are presented and analyzed. Recommendations are given for performing microfrac tests in these formations. performing microfrac tests in these formations
The past fifteen years have witnessed the progressive development of the large progressive development of the large hydrocarbon reserves, 1350 x 10 to the 9th bbl (214 x 10 to the 9th m), located in the oil sands deposits of Alberta. Two major surface mining operations are currently in operation in the Athabasca deposit, but less than 10% of the area is shallow enough to allow surface mining operations. Therefore, other recovery strategies are being investigated or used for the remaining oil sands. Esso Resources is operating a full scale in situ production project in the Cold Lake deposit production project in the Cold Lake deposit involving steam stimulation techniques. Due to high bitumen viscosities (e.g. 3 x 10 to the 6th cp (3.0 x 10 to the 3rd Pa.s)) under reservoir conditions, the bitumen will not readily flow through the sand matrix. Thermal methods, such as cyclic steam stimulation and steam flooding, are used to improve the bitumen mobility. In the most common technique, cyclic steam stimulation, the payzone is fractured to improve the areal payzone is fractured to improve the areal conformance of the steam.
Field performance and research have shown that the in situ stress state is the first order control on hydraulic fracture behaviour. For oil sands, shear failure may occur prior to tensile fracturing depending on the relationship between the in situ stresses and the formation pore pressure. Rational design of well patterns, pore pressure. Rational design of well patterns, spacing, and operating procedures requires knowledge of the in situ stresses along with geomechanical properties of the oil sands. The small volume hydraulic fracture test, the microfrac test, is the only method available for measuring in situ stress at reservoir depth. Although hydraulic fracturing stress measurements have been practiced for many years, it has only been recently that the test method has been standardized. Furthermore, the analysis of hydraulic fracturing tests for determining in situ stresses remains the subject of varying interpretation as shown by the papers of the 1988 International Workshops on Hydraulic Fracturing Stress Measurements.
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.
The existence of thin films of water that completely wet the sand grains has long been regarded as an important feature of the Athabasca oil sands deposit. Direct microscopic evidence, however, cannot be relied on to establish whether such films are present. The existence and stability of such films, therefore, must be inferred from the relevant surface chemical forces for the oil/brine/rock system. A detailed analysis of these forces shows that the stability of these thin wetting films is critically dependent on whether the zeta potentials (and charge densities) for the two electrical double layers bounding the film are of like sign. The zeta potential and charge density for the rock/brine interface will in almost all cases be negative in sign. Therefore, a requirement for the stability of a wetting film will be that these quantities are also negative at the brine/oil interface. New measurements of the electrophoretic mobility of small particles of Athabasca bitumen suspended in an aqueous phase are reported. These data show that the zeta potential at the bitumen/water interface is strongly negative. Consequently, these results suppose the hypothesis that wetting films will be stable in this instance.
The great economic potential and geological significance of the Athabasca oil sands, as well as ready accessibility of outcrop specimens, have motivated extensive investigations of their chemical and physical properties for the past several decades. Although many details remain still unresolved, there is broad agreement regarding the gross physical nature of the quartz/bitumen/water mixture that constitutes the bulk of the resource. In particular, it is usually postulated that, even in the particular, it is usually postulated that, even in the bitumen-rich deposits where water content is very low, the aqueous phase is distributed in the form of continuous films that surround the quartz grains. In other words, the grains themselves are separated from the bitumen phase by envelopes of water. These envelopes are presumed to be much thicker than a simple monolayer or bilayer of water molecules (0.3 to 0.6 nm). The first published suggestion of such an arrangement was appended as a reader's comment to a general review of Athabasca oil-sands geology. Since then, others have reaffirmed this idea, occasionally pointing out also that, while present in the Athabasca material, such aqueous envelopes, separating oil from sand, are not an essential feature of all oil and tar sands. It is of some interest, however, so far as the Athabasca oil sands are concerned, that no direct observation of water films of greater-than-molecular thickness seems ever to have been made: thus, the evidence is, to date, indirect and equivocal. There is no doubt that the question of whether such wetting films are present is of more than academic importance. Rapid, complete separation of the Athabasca bitumen from sand is a key requirement for both current methods of mining and future in-situ technology. The modeling and optimization of such processes clearly will depend on a correct interpretation of the physical mechanisms involved, and this in turn requires a valid assessment of the initial physical state of the system.