Canada’s oil sands are one of the world’s largest hydrocarbon resources. The initial volume of crude bitumen in place is estimated to be approximately 260 billion cubic metres with 11 percent or 28 billion cubic metres recoverable under current economic conditions. Continually improving economics, bolstered by recent higher crude oil prices, has resulted in the International recognition of the vast potential of Canada’s oil sands. Based on publicly announced development plans through to 2015, over C$60 billion could be invested in numerous projects to develop the oil sands. Various factors have to be considered to select the proper cement for zonal isolation of thermal recovery heavy-oil wells. First the cement should be flexible enough to withstand the stresses which occur when casing expands during the heating up of the well. To reduce these stresses, the cement thermal expansion coefficient should be similar to the thermal expansion coefficient of the casing. Finally, cement mechanical properties should not degrade during the whole steam injection process, i.e. when it is subjected to extremely high temperatures (up to 350 degC) for extended periods of time. Specifically in Canada, the majority of the steam injection wells are drilled in shallow sandstone formations. This requires the cement to have high flexibility to resist the stresses. Moreover, during steam injection, a reaction between the sandstone formation and the cement sheath may occur, impacting the cement matrix and hence changing its properties. This paper describes the application of a new thermally responsive cement for zonal isolation of heavy oil wells in Canada. This system is designed to have excellent strength, flexibility and thermal properties even upon interaction with sandstone formations. It minimizes the mechanical stresses exerted on the cement sheath during steam injection, thus reducing the risk of loss of well integrity. The numerical simulations performed with these long-term material properties (six months of exposure to 350 degC) for typical Canadian heavy oil wells conditions predict reliable and durable zonal isolation under these extreme conditions. These simulation results are confirmed by several field applications in wells which have not leaked after months of steam injection.

Operators involved in the recovery of hydrocarbons from heavy-oil reservoirs often face the problem of maintaining well integrity in steam-injection wells. A significant portion of these wells suffer various forms of leaks and in the most severe case complete steam breakthrough to surface. Throughout the life of heavy-oil wells, cement material degradation and stresses in the cement sheath induced by extreme temperature cycling result in severe mechanical damage and ultimate failure of the cement sheath. These problems motivate different operators to explore new cementing technologies that are capable of achieving reliable longterm zonal isolation in these extreme conditions.The main challenge for operators is to design thermally stable cement with mechanical properties sufficient to withstand stresses induced by the large temperature changes. This paper describes the development of a new cement system, which is stable, strong, impermeable and flexible up to a temperature of at least 350°C(650°F), corresponding to the maximum steam injection temperature. Depending on the curing temperature this new cement system provides low Young's modulus of 1,800 to 4,000 MPa while maintaining excellent compressive and tensile strengths compared to cements currently used in the oilfield industry. Aging the cement system for 6 months at steam temperatures demonstrates the stability of the set material properties, including maintaining a low permeability.Field trials in North America show that this new cement system can be easily implemented into standard cementing operations using conventional equipment. Cement evaluation logs after cement operations confirm that excellent zonal isolation and wellbore integrity are readily achieved.By keeping adequate strength and flexibility, this new cement system reduces the risk of cement sheath failure and steam migration throughout the life of these steam-injection wells. It provides a long-term well integrity solution for any well exposed to very large temperature increase after the cement initial set, such as in fields exposed to steam temperatures.

Expansion of oilwell cement after placement in the annulus is a promising route to improve wellbore sealing. Expansion can potentially provide benefits such as: closing a microannulus, reducing the tendency for cracking/debonding, and improving cement logging evaluation. To properly evaluate the performance of expanding cement formulations in a laboratory setting, the cement should be hydrated under confined conditions similar to a wellbore. We conducted measurements using a new confinement cell developed in our laboratory. The cell provides radial confinement and elevated temperature as in a wellbore. The availability of water to the cement can also be controlled to simulate tight or porous formations. In the axial direction the cement sample contacts a piston that either confines the sample while measuring the axial stress development, or permits linear expansion that is measured. Using blends of oilwell cement with magnesium oxide (MgO), a standard expanding additive, we measured the axial stress development and linear expansion under different curing conditions. To better understand and optimize cement expansion we also characterized the hydration kinetics of the MgO additive alone and in the presence of the cement, using isothermal calorimetry. Finally, we measured the acoustic response of cement formulations with and without a commercial expanding agent with a standard ultrasonic pulseecho technique. This testing confirmed the benefits of expansion for the logging response.

A major challenge of a steamflooded field in Indonesia, one of the world's largest thermal recovery projects, is the short life of the well from the well integrity aspect. The outcome of a joint study group between the operator and the cementing service provider reveals that 77% of the injector wells drilled in a recent period of 5 years required remedial squeeze cementing operations. The operating expenditure of workover operations and the costs of the deferred production to the operator are significant; hence, a cementing solution is needed to improve the efficiency in managing the mature heavy oil reserve. The current cementing practice calls for placing the API class G cement and silica flour blended system across unconsolidated sand bodies and exposing it to large temperature changes. Results of the stress modeling predict the conventional cement system failure under the anticipated conditions of injection and workover operations. An innovative steam-resilient cement system with tailored thermal and mechanical properties up to a temperature of at least 350° C [650° F], beyond the maximum steam injection temperature of the field, is maintaining the integrity. Field trials in Indonesia confirm that this new system can be easily integrated into standard cementing operations using conventional equipment. Cement evaluation logs after cement operations prove that proper zonal isolation is achieved. All the candidate wells, first one since January 2011, are currently under the steam injection with no sign of wellbore integrity failure. This novel cement system, by keeping adequate level of flexibility and optimum thermal properties, provides a long term well integrity solution for any well exposed to similar conditions, such as in fields exposed to steam injection. Operators can rely on cement sheath integrity exposed to thermal processes to produce heavy oils.

A major challenge of a steamflooded field in Indonesia, one of the world's largest thermal recovery projects, is the short life of the well from the well integrity aspect. The outcome of a joint study group between the operator and the cementing service provider reveals that 77% of the injector wells drilled in a recent period of 5 years required remedial squeeze cementing operations. The operating expenditure of workover operations and the costs of the deferred production to the operator are significant; hence, a cementing solution is needed to improve the efficiency in managing the mature heavy oil reserve.The current cementing practice calls for placing the API class G cement and silica flour blended system across unconsolidated sand bodies and exposing it to large temperature changes. Results of the stress modeling predict the conventional cement system failure under the anticipated conditions of injection and workover operations. An innovative steam-resilient cement system with tailored thermal and mechanical properties up to a temperature of at least 350⁰ C [650⁰ F], beyond the maximum steam injection temperature of the field, is maintaining the integrity.Field trials in Indonesia confirm that this new system can be easily integrated into standard cementing operations using conventional equipment. Cement evaluation logs after cement operations prove that proper zonal isolation is achieved. All the candidate wells, first one since January 2011, are currently under the steam injection with no sign of wellbore integrity failure. This novel cement system, by keeping adequate level of flexibility and optimum thermal properties, provides a long term well integrity solution for any well exposed to similar conditions, such as in fields exposed to steam injection. Operators can rely on cement sheath integrity exposed to thermal processes to produce heavy oils.