Thermal recovery methods are used to produce the heavy oil (bitumen) located in a 30 meter thick sand layer in the Peace River fields of northwestern Alberta. An estimated 8-10 million barrels of bitumen lie in place in this field, at a reservoir depth of approximately 600 meters.

The production strategy of choice is Cyclic Steam Stimulation (CSS), otherwise referred to as ‘huff n’ puff’ is a three-stage in-situ thermal recovery process. The first phase involves several weeks (sometimes months) of high-pressure steam injection, where steam is pumped into the oil sand formation, to heat the bitumen, reducing its viscosity and separating it from the sand. The second phase is the ‘soak’ phase, where the steam is turned off and the reservoir is left to soak up the steam and the moisture. Finally, during the production phase, the injector wells are reversed and used to pump the mobilized bitumen to the surface. The oil is produced until the recovery begins to diminish, and then the cycle is repeated.

In this field, the client uses multi-lateral horizontal well design. A series of vertical wells are drilled from the center of the pad, down to the reservoir level where the wells branch off into horizontal laterals, moving away from the well pad center.

Challenge

Initially, the client believed that heat propagated through the reservoir by a combination of dilation and thermal convection, this particular model also assumed that the steam chamber developed in a uniform cylindrical manner. However, there was still considerable uncertainty in terms of the entire process.

The main issue the client was experiencing was that they had little detailed knowledge of the subsurface processes occurring within the reservoir. In particular it was not really known how steam develops and moves within the reservoir. This lack of understanding made it difficult to optimize drilling and production operations to maximize recovery and improve well design.

Detailed knowledge on steam development and movement, identification of bypassed oil regions, was needed in order develop optimization strategies.

In order to reduce their uncertainty, the client decided to undergo a pilot monitoring program encompassing various geophysical techniques, including microseismic monitoring.

ESG Solution

ESG was contracted to provide the microseismic monitoring component of the pilot project. A feasibility study was conducted by ESG to determine the optimal design of the monitoring system, based on the geological characteristics of the reservoir.
Based on the feasibility study, ESG designed and deployed a 50 level array of dual 3-component triaxial geophones. This customized sensor array was cemented into a 45 degree deviated observation well, located near the center of the pad, to provide optimal coverage and detectability of the microseismic events associated with steam movement.

ESG also installed their proprietary Paladin™ data acquisition units and a DSL/Fiber optic Ethernet based communication signal to capture the downhole data and relay it to the centralized well pad computer.

Microseismic data was transmitted via satellite link to ESG’s processing center, where teams of geophysicists and data processors further analyzed and interpreted the data. ESG’s reporting and visualization services were used to provide the client with real-time images of the microseismicity within the reservoir, which could be used to define the steam front and infer steam behavior. 

Fig. 1: Microseismicity associated with cyclic steam stimulation 

ESG’s instrumentation was also used in conjunction with time-lapse 3D VSP and surface-to-surface seismic surveys. Integration of different monitoring techniques provided more insights into understanding the reservoir processes. For instance, through use of time-lapse surveys, combined with core data, it became apparent that the heat was penetrating the more porous reservoir sands, and avoiding the less permeable areas. 

Fig. 2: RMS amplitude during cyclic steam stimulation

Locations of microseismic events plotted within the reservoir contradicted the previous assumptions about heat transfer. Fracturing of the reservoir was indeed taking place, but not uniformly distributed, with some areas experiencing extensive fracturing, and others being relatively inactive. Microseismic activity was correlated with time-lapse surveys, revealing that the microseismic events associated with steam generated fractures were occurring at the edge of the heated zone, so the steam was fracturing the rock as it hit the less permeable area of the reservoir. Continued monitoring later revealed that the heated area would eventually expand into these fractured areas.

Monitoring also gave insight into fracture development. By analyzing trends in the microseismic event locations, it became apparent that the fracture growth was following zones of weakness within the reservoir, caused by local stress changes.

The monitoring program also provided significant insight into steam controls. The original steam injection design has steam being pumped into three lateral kickoffs from the central vertical well. The distribution of heat and microseismic events however, indicated that only one of these wells was instrumental in putting significant amounts of steam into the reservoir.

Outcome

The information provided by microseismic monitoring, proved that the original model of uniform steam development, and heat transfer through thermal convection and dilation was in fact incorrect. Instead, steam distribution is greatly influenced by the geology, as it pertains to the permeability of the sand formation. The creation of fracture networks was identified as an important mechanism to get steam into less permeable areas of the reservoir. However, because these fracture networks can be influenced by pre-existing stress patterns, it is necessary to consider these elements when designing and drilling wells.

The client was able to use microseismic monitoring as a tool to determine how successfully new fractures have been created, and based on that infer how successful their steaming program is. Higher rates of microseismicity mean more fractures are being developed. As a result, the operators increased their treatment pressure to get more steam into the reservoir. 

Fig. 3: Microseismic events and injection pressure

The client was also able to make changes to their steaming controls, stopping the multi-lateral steam injections that were proven to be ineffective. In one instance microseismicity detected spreading into the buffer zones between producing and injecting well pads (which were at minimum and maximum pressures) giving operators and indication that steam may be escaping. The injection was safely terminated before the steam could break through into the producing well pad.

The use of microseismic for thermal monitoring and optimization has been subsequently incorporated into many other well pads at this client’s site, and is being used by other clients in the U.S and the Middle East.

References:
McGillivray P, 2005 – Microseismic and time-lapse seismic monitoring of heavy oil extraction process at Peace River, Canada. CSEG Luncheon 24 January 2005.
Maron K, Bourne S, Wit K, McGillivray P, 2005 – Integrated reservoir surveillance of a heavy oilfield in Peace River, Canada, C034 EAGE 67th Conference and Technical Exhibition, Madrid, June 2005