Strength in Flexibility

This high-temperature steam, however, creates significant stresses on the cement sheaths in the wells-especially when inevitable shutdowns create cooling and heating cycles. These extreme changes in temperature threaten the stability of the sheaths and therefore their ability to provide zonal isolation.

In response to SAGD and other high-pressure, high-temperature cycling scenarios, Schlumberger designed FlexSTONE flexible cement. Once in place, the FlexSTONE cement sheath's flexibility (the result of a Young's modulus of 2,000 to 6,000 MPa) allows it to conform to casing contraction and expansion while maintaining its seal.

Speaking at a recent gathering of oil and gas professionals, Schlumberger cementing services engineer, Gunnar DeBruijn compared the results of cementing 7 SAGD pairs (14 wellbores); two were cemented using FlexSTONE slurry while the remainder used a thixotropic cement that exhibits a Young's modulus of about 5,500 MPa. The wells were in a heavy-oil field near the town of Anzac, Alberta, Canada.

Working through an alliance contract with operator PEMEX, Schlumberger Integrated Project Management tried a different solution: injecting the nitrogen not down the drillpipe but through the concentric casing annulus. With this change, the nitrogen entered the mud column below the motor and the directional tools. The result was a column of fluid of sufficient density to facilitate mud pulse data transmission and to keep the motor seals from being exposed to gas.

Adding to the concerns about cement integrity presented by the cyclical stresses is the difficulty of maintaining casing centralization in the soft formations associated with heavy-oil deposits. Likewise, it can be difficult to evaluate the bond between the cement and formation after steam injection. By following best practices, however, and refining those practices in successive wells, Total and Schlumberger engineers were able to overcome these challenges.

The critical difference between the two cement systems was demonstrated in simulations that involved bringing the wells from their "cooled" temperature to 250 degC without sheath failure. In the injector wells, the shortest time to that point was 3 days for the wells cemented with the FlexStone system and 6 days for those cemented with the thixotropic cement. Likewise, for producers it was 1 and 1.5 days and maximum pressure to failure was 5 and 4 MPa, respectively.