A Core Scale Investigation of Drainage Displacement

ABSTRACT

Water flooding has been applied either along with primary production to maintain reservoir pressure or later to displace the oil in conventional and heavy oil reservoirs. Although it is generally accepted that water flooding of light oil reservoirs in oil-wet systems delivers the least oil compared to either water-wet or intermediate-wet systems, there is a lack of systematic research to study water flooding of heavy oils in oil-wet reservoirs. This research gives some new insights on the effect of injection velocity and oil viscosity on water flooding of oil-wet reservoirs.

Seven different oils with a broad range of viscosity ranging from 1 to 15,000 mPa.s at 25 °C were used in fifteen core flooding experiments where injection velocity was varied from 0.7 to 24.3 ft/D (2.5 × 10⁻⁶ m/s to 86.0 × 10⁻⁶ m/s). Oil-wet sand (with contact angle of 159.31 ± 3.06°) was used in all the flooding experiments. Breakthrough time was precisely determined using an in-line densitometer installed downstream of the core.

Our observations suggest that drainage displacement does not occur unless non-wetting (water) phase pressure exceeds a critical breakthrough capillary pressure. At the same injection velocity, this non-wetting phase invading pressure is a function of the viscosity of the oil being displaced. For the same viscosity ratio, oil recovery monotonically increases with increasing injection velocity suggesting that the flow regime is viscous-dominant for all the viscosities studied. This is consistent with the classical literature on carbonates (deZabala and Kamath, 1995). However, the current work extends the classical learnings to a much wider operational envelope on oil-wet sandstones.

In this paper, it is demonstrated that in an oil-wet system increasing velocity improves forced drainage to the extent that it takes over viscous fingering. For the viscous oil system (15,000 mPa.s), it was found that wettability critically affects the pressure gradient across the core to the extent that one order of magnitude larger pressure gradient was observed in an oil-wet system compared to the completely same system but water-wet. This notable larger pressure gradient in oil-wet system accompanies with delayed water breakthrough leading to incremental (around 30 % OOIP) oil recovery compared to the water-wet case. This is completely opposite to the classical literature on light oils and needs to be further investigated due to the lack of literature on heavy oil domains. Observations reported in this study can provide some useful information about the sizes of the pores being invaded as a function of oil viscosity and wettability, which is a subject of our future microfluidic studies at the pore scale.

A full version of this paper is available on OnePetro Online.