ABSTRACT

Two cores were examined from a Cold Lake oil sands pilot plant. One core (T1) was sampled before any steam had been injected. A second core (EX), 15.25 m (50 ft) from the T1 core and 30.5 m (100 ft) from the injection well, was sampled after nearly two years of continuous-drive steam injection. Temperatures recorded in the T1 bore hole reached 250°C in some zones. Examination of well logs and core shows a marked decrease in total porosity after steam injection, but relatively good recovery rates.

Detailed analytical examination by scanning electron microscopy (SEM) of sandstones from the T1 and EX cores indicates that original, fine (<2 µm) authigenic coatings of illite, smectite, minor zeolites, and chlorite are replaced by relatively coarse (4-10 µm) smectite and large (20-30 µm) euhedral analcime crystals. The development of smectite in the steamed (EX) core is most noticeable in the slushed interval (steam injection interval) and corresponds to a doubling of the amount of smectite in the <2 µm fraction detected during X-ray diffraction examination. Thin-section petrography does not reveal any major influence on the framework grains; only pore-space mineralogy is noticeably affected.

The reduction in total porosity in the vicinity of the slushed zone is partially a function of the growth of smectite but may also involve compaction of framework grains upon removal of oil. A visible reduction in permeability, a significant decrease in effective porosity, and the trapping of oil in post-steam material can be related to the morphology and growth habit of the smectite. Smectite develops to a greater extent on unstable framework grains (e.g., volcanic clasts) and in this respect may serve as a form of protection against the potentially destructive high-temperature steam.

All samples examined in this study had initially high total porosities and relatively low clay content. Petrographic relationships indicate that loss of porosity in rocks of initially lower porosity and/or higher clay content would cause significant reductions in oil recovery rates.

Observed decreases in porosities (as determined from well logs) and oil recovery rates (determined by laboratory analyses) are related to the apparent growth of smectite from kaolinite and detrital feldspar. The textural information also indicates that analcime formed at a late stage of mineral growth.

The observed mineral reactions can be modelled by using equilibrium phase relationships among the minerals smectite, kaolinite, albite, analcime and quartz in the presence of water containing sodium. While no truly quantitive information can be derived from these phase relationships, the qualitative trends in fluid compositions as mineral reactions proceed can be predicted. The fluid composition trends are consistent with the observed mineralogy and textural relationships, and may provide a method for monitoring mineralogical alteration during steam injection.