Page 76 - Formation Damage during Improved Oil Recovery Fundamentals and Applications

58 David A. Wood and Bin Yuan

yielding between 4.5% and 9% of incremental OOIP compared to a
high-salinity WAG process.
Field-scale simulation indicated that the WAG ratio has a large effect
on the ultimate oil recovery with a WAG ratio of 1:2 resulting in the
highest oil recovery for the Brugge oil field case. The longer the CO 2 -
LSWAG cycling is applied, the greater the benefit in terms of oil recov-
ery. Also, the shorter the water injection period involved in each WAG
cycle, the greater the ultimate oil recovery. Of course, these latter two
recovery benefits come at the cost of additional CO 2 required for
injection. It is important to design the WAG parameters carefully
(Batruny and Babadagli, 2015), on a field-by-field basis taking into
account historical water injection, if appropriate.
The success of CO 2 -LSWAG is also reported by Dang et al. (2016)
who identify a number of factors that are likely to have variable impacts
for each oil field and reservoir. These factors require careful evaluation
and analysis with pilot well tests and field trials in addition to simulations.
These factors include:
• type and quantity of clay minerals
• initial reservoir wettability condition
• reservoir heterogeneity
• nonsilicate reservoir mineralogy (e.g., calcite and dolomite)
• composition of formation water and injected brine
• reservoir pressure and temperature for achieving CO 2 miscible
condition, and
• WAG parameters

2.11.4 LSWF combined with nanofluid treatments
On the one hand, the problem of fines migration induced by low-salinity
water can improve mobility control as already described. However, the
straining effects of fines also bring significant damage to formation
permeability and the subsequent increase of injection pressure. This places
strain on the management of surface facilities with loss of economic
profits.
In the radial flow system, the majority of pressure loss is attributed to
the tremendously large flow in close vicinity to the wellbores. Because of
the differences in flowing velocities through each layer, the distributions
of maximum retention concentration of fines are also not identical for
each layer. Yuan and Moghanloo, (2017b, 2018c) introduced different