Monitoring of Steam Stimulation in the McMurray Formation, Athabasca Deposit, Alberta
Authors: Singhal Ashok K. , Card Colin C. 
Published: December 2007

Because of injectivity considerations, injection schemes in the Athabasca deposit often require creation of fractures. Bitumen recovery is linked to the heat and fluid distribution obtained in the reservoir. Hence, to optimize the performance of the process, one needs to monitor closely the mechanical and thermal disturbance caused by steam injection in the reservoir formation. The objectives of the monitoring program described in this paper wereto obtain input data for numerical simulation studies so that subsequent optimization of the process could be undertaken,to verify assumptions/speculations on the process mechanisms, andto obtain diagnostic information.

Six wells were steam stimulated. The monitored data included tiltmeter records on all wells, injection-pressure/flow-rate data, produced-water salinity analyses, limited pressure-falloff analyses, data from a few pressure observation wells, first-order leveling, and self-potential (SP) and resistivity mapping. From these observations, the existence and nature of fractures around different wells were inferred. The study confirmed that a combination of various monitoring techniques enhances the reliability of interpretations. For obtaining process data in a cost-effective manner, monitoring programs that rely heavily on conventional data collection from injection and production wells are recommended.

Introduction

Exploitation of the huge in-place reserves of McMurray oil sands in northeastern Alberta offers a formidable engineering challenge because of the very viscous nature of the hydrocarbons and the highly variable nature of the formation. The hydrocarbon have viscosities exceeding 106 cp [106 mPa·s] under reservoir conditions at most places in the Athabasca deposits. Very few in-situ methods seem feasible for recovering this bitumen. Steam stimulation is one of the recovery techniques being evaluated in several projects in Athabasca.

The oil recovery during steam stimulation will be governed to a large extent by the distribution of regions where oil would be mobilized as a combined result of heating, pressurization, and drawdown. It follows that a knowledge of where steam travels within the pay zone will provide clues about the extent of oil mobilization. Only after gaining understanding about the distribution of steam within the reservoir under various conditions can one attempt to optimize the process. In view of large economic risks and gross reservoir variability, such an optimization is highly desirable.

In most oil-sand areas, injection of any significant amounts of steam (or fluid for that matter) often requires creation of fractures. Monitoring of fractures (initiation as well as propagation and collapse) may provide important information about the distribution of injected fluids (steam) within the reservoir. This and other clues may be inferred from indirect measurements, which manifest perturbations caused by the injected fluids. These may include ground elevation changes resulting from heating of fluids and rocks (first-order leveling), changes in slopes of near-surface formation (tiltmeters), surface temperature mapping (infrared imaging), generation of elastic waves caused by mechanical shocks (seismic) associated with deformations, and changes induced in the electromagnetic environments by temperature and electrolytic changes (SP, resistivity, and magnetic field changes). Of course, there also exist more direct observations, such as fluid production history; fluid/solids analyses; temperature, pressure, and saturation observations within the reservoir (observation wells as well as injection/production wells); and coring of the reservoir at strategically selected points and appropriate time intervals.

Characteristics of McMurray Formation.

The McMurray formation, the main bitumen-bearing zone in the Athabasca deposit, is a member of the Mannville group (Lower Cretaceous). This zone is conformably overlain by the Wabiskaw formation and underlain by Devonian carbonates beneath an erosional unconformity. The McMurray zone is essentially a fluvial channel deposit transitioning into marginal tidal-marine-flat deposits toward the top of the zone. Individual identifiable channels can be stacked over one another, but are more commonly crisscrossed throughout the area as a result of channel shifting and meandering during deposition. Horizontal continuity across the channels at many places cannot be ensured for distances exceeding 200 to 1,300 ft [60 to 400 m], but much greater continuity can exist along the channels. The region south of Fort McMurray, after being subjected to huge overburden pressures in the geological past, is currently under about 1,000 ft [300 m] of overburden. About 10 to 300 ft [3 to 90 m] of the overburden consists of weathered zone/alluvial sands/glacial till. The remaining overburden comprises Cretaceous (Mannville) formations, consisting of sand/shale sequences, with some of the sands containing gas, water, or bitumen. The Cretaceous beds are essentially flat.1 At places, there are indications of salt collapse originating in the underlying Devonian strata. A study of the outcrops of Devonian and Cretaceous sediments in the general area reported orthogonal sets of joints along the northeast and northwest directions.2 Other than these, the region has been tectonically relatively quiet.

The McMurray formation is a complex and highly variable stratified reservoir consisting of interbedded sands, laminated silts, and clays. At certain random places within the bitumen-bearing sections, layers with some mobile water occur. The gross thickness of McMurray zone varies between 200 and 300 ft [60 and 90 m] and the net pay thickness between 0 and 240 ft [0 and 70 m]. The best individual pay sand, 35 to 50 ft [10 to 15 m] thick, usually occurs toward the bottom of the McMurray zone, often underlain by a bottomwater zone.

It is speculated that because of the actions of circulating groundwater and associated bacteria over the geological past, the once light oil has by now degenerated into a highly viscous bitumen. Because of areal and vertical heterogeneities in the reservoir coupled with features of paleo-hydrological regimes, the bitumen is variable in quality. The associated brine is relatively very fresh [2,000 to 20,000 ppm total dissolved solids (TDS)] and can be quite different at each well location.

Characteristics of McMurray Formation.

The McMurray formation, the main bitumen-bearing zone in the Athabasca deposit, is a member of the Mannville group (Lower Cretaceous). This zone is conformably overlain by the Wabiskaw formation and underlain by Devonian carbonates beneath an erosional unconformity. The McMurray zone is essentially a fluvial channel deposit transitioning into marginal tidal-marine-flat deposits toward the top of the zone. Individual identifiable channels can be stacked over one another, but are more commonly crisscrossed throughout the area as a result of channel shifting and meandering during deposition. Horizontal continuity across the channels at many places cannot be ensured for distances exceeding 200 to 1,300 ft [60 to 400 m], but much greater continuity can exist along the channels. The region south of Fort McMurray, after being subjected to huge overburden pressures in the geological past, is currently under about 1,000 ft [300 m] of overburden. About 10 to 300 ft [3 to 90 m] of the overburden consists of weathered zone/alluvial sands/glacial till. The remaining overburden comprises Cretaceous (Mannville) formations, consisting of sand/shale sequences, with some of the sands containing gas, water, or bitumen. The Cretaceous beds are essentially flat.1 At places, there are indications of salt collapse originating in the underlying Devonian strata. A study of the outcrops of Devonian and Cretaceous sediments in the general area reported orthogonal sets of joints along the northeast and northwest directions.2 Other than these, the region has been tectonically relatively quiet.

The McMurray formation is a complex and highly variable stratified reservoir consisting of interbedded sands, laminated silts, and clays. At certain random places within the bitumen-bearing sections, layers with some mobile water occur. The gross thickness of McMurray zone varies between 200 and 300 ft [60 and 90 m] and the net pay thickness between 0 and 240 ft [0 and 70 m]. The best individual pay sand, 35 to 50 ft [10 to 15 m] thick, usually occurs toward the bottom of the McMurray zone, often underlain by a bottomwater zone.

It is speculated that because of the actions of circulating groundwater and associated bacteria over the geological past, the once light oil has by now degenerated into a highly viscous bitumen. Because of areal and vertical heterogeneities in the reservoir coupled with features of paleo-hydrological regimes, the bitumen is variable in quality. The associated brine is relatively very fresh [2,000 to 20,000 ppm total dissolved solids (TDS)] and can be quite different at each well location.