Page 69 - Formation Damage during Improved Oil Recovery Fundamentals and Applications

Low-Salinity Water Flooding: from Novel to Mature Technology 51

conditions in terms of these parameters by matching their experimental
results. This approach offers a potentially useful method for monitoring
wettability changes during dynamic reservoir water injection programs,
making it possible to delineate progress and identify areas of formation
damage (beneficial and detrimental) in LSWF projects.

2.9 WETTING MECHANISMS IN CARBONATES AND
SANDSTONES
The distribution of oil and water in the porous system is linked to
the wetting properties of the crude oil-formation water-rock matrix
interface system, i.e., the contact between the rock surface and the two
fluids, crude oil and formation fluid (a complex brine with varying
salinity and ionic components). Referring to formation water as brine
suggests to simplistic a composition for this key, but highly variable, com-
ponent of the system.
The wetting properties of this system dictate, to an extent, how the
two fluid phases in the system with flow-phase fluid flow the porous
network of an oil reservoir, by influencing the capillary pressure, Pc, and
the relative permeabilities of oil and water, kro, and krw, which in turn
influence oil recovery (Jadhunandan and Morrow, 1995); systems that are
slightly water wet tend to show the best incremental oil recovery through
water flooding.
Austad (2013) makes the important distinction between water flooding
as a secondary and tertiary recovery technique: injection of its own
formation water into an oil reservoir is a secondary recovery process;
injection of water with a different composition to the initial formation
water may change wetting properties of the reservoir (for better or worse
from an oil recovery process) and is therefore a tertiary recovery process.
Wetting characteristics of carbonates and sandstones are quite distinct.
Oil recovery from carbonates is typically less than 30% due to low
water wetness, the presence of natural fractures, low permeability, and
inhomogeneous rock properties. This is due to the strong bond between
the negatively charged carboxylic group, COO (present in heavy
components of crude oil) and the positively charged sites on carbonate
surface (Fathi et al., 2011; Austad, 2013). Higher temperature carbonate
reservoirs are more likely to be water-wet (Rao, 1996) as temperature