Page 28 - Formation Damage during Improved Oil Recovery Fundamentals and Applications

Overview of Formation Damage During Improved and Enhanced Oil Recovery 11

tends to decrease the solubility of asphaltenes in oil, and therefore acts as
a precipitant for asphaltene. It does so by lowering the threshold of
asphaltene precipitation (Gholoum et al., 2003), which can result in
blockages of the reservoir pore throats, and damage to oil production by
inducing reservoir rock wettability reversal with decrease in oil relative
permeability (Novosad and Costain, 1990). CO 2 flooding can also result
in the formation of carbonic acid, which lowers pH and increases Eh (activ-
ity of electrons) to dissolve quartz, feldspar, barite, anhydrite, mica, calcite
(in some conditions), cements and some clays, including smectite, illite, and
kaolinite (Chopping and Kaszuba, 2012; Miranda-Trevino and Cynthia,
2003). This leads to permeability damage through the movement of
detached fines, precipitation of dissolved clays into pore throats, and the pre-
cipitation of calcite can be induced by the reactions between CO 2 and cal-
21
cium ions (Ca )inthe formation water (Plummer and Busenberg, 1982).

1.8 HYDRAULIC FRACTURING IN SHALE FORMATIONS

Multistage fracturing in long horizontal wellbore sections has made
shale oil and gas one of the most rapidly growing sources of worldwide
energy supply (Yuan et al., 2015a,b; Yuan et al., 2017c; Zheng et al.,
2016). However, the success and sustainability of oil and gas production
from shale strongly depends on being able to avoid the reduction of frac-
ture conductivity and matrix deliverability caused by formation damage
mechanisms (Davudov et al., 2016). Major formation damage mechanisms
during the production from shale reservoirs include the loss of fracture
conductivity caused by proppant transport and its nonuniform placement
(Liang et al., 2016), embedment and crushing (Kang et al., 2014), fine
migration and plugging (Zhang et al., 2015a,b), gelling damage (Shaoul
et al., 2011), and multiphase flow effects (Palisch et al., 2007). To solve
the above damage problems, the following strategies can be applied, such
as: foam-based fracturing fluids (Tong et al. 2017), and CO 2 foam stabi-
lized fluids (Xiao et al., 2016), LPG-based fracturing fluids (Lestz et al.,
2007; Zhao et al., 2017), low-density soft proppant (Jackson and Orekha,
2017), channel fracturing technique (Wang et al., 2018), and pumping
design optimization (Bestaoui-Spurr and Hudson, 2017). Moreover, the
severe damage of the reservoir matrix can be attributed to the pore