Page 374 - Fundamentals of Gas Shale Reservoirs

354 WETTABILITY OF GAS SHALE RESERVOIRS

the surface tension and viscosity of the imbibing fluid, 4
respectively. θ is the equilibrium contact angle of water or oil R C
on the rock surface. Handy (1960) developed a similar rela- R H
tionship between the imbibed volume and time: 3 R V
2
2 Pk AS
Q 2 c t (16.3) 2

where Q is the volume of imbibed liquid, k is effective liquid 1
permeability, is fractional porosity, A is the cross‐sec-
tional area of sample, S is the liquid saturation behind the 0
imbibition front (Li and Horne, 2001), μ is the liquid vis- FS M OP
cosity, and P is capillary pressure at the saturation of S.
c
Based on this model, the ratio between the square of imbibed FIGURE 16.12 The ratio between water and oil imbibition rate
volume and time is given by into crushed shale packs based on the imbibition theory (R ),
C
horizontal imbibition experiments (R ), and vertical imbibition
H
2
Q 2 2 Pk AS experiments (R ).
V
C c (16.4)
t
Now let us consider water and oil imbibition into two 16.6 ESTIMATION OF BRINE IMBIBITION AT
separate porous media with similar size, porosity and perme- THE FIELD SCALE
ability. The ratio between the C values for water and oil
imbibition is given by Hydraulic fracturing is a key stimulation technology for
hydrocarbon production from the shale reservoirs. Fracturing
C P ( / ) (cos /) fluids containing proppants and chemicals are pumped into
R water c water water (16.5)
C the formation to create hydraulic fractures. Recent studies
C P (/ ) (cos /)
oil c oil o oil
show that fractured shale reservoirs retain a significant
This equation can be used to predict the ratio between fraction of injected fluid volume. This fact can lead to
water and oil imbibition rate into crushed shale packs, which formation damage, early‐time high gas production rate,
are relatively homogeneous and isotropic. Substituting oil heavy consumption of water, and subsequent environmental
and water properties into Equation 16.5 gives the R values issues (Chapman, 2012; Soeder, 2011).
C
in the range of 2–3, as shown in Figure 16.12. Therefore, The water retained in the reservoir can leak into the rock
based on current theories of imbibition and approximation matrix due to capillary effect and lead to formation damage
of Young–Laplace equation for capillary pressure, water (Bennion and Thomas, 2005; Holditch, 1979; Le et al., 2009;
should imbibe faster than oil in all the shale samples studied Shaoul et al., 2011). Wang et al. (2012b) investigated the
here. This is primarily because the surface tension of water impact of each damage mechanism individually and also
is more than two times higher than that of oil. However, the concluded that a higher fracturing water recovery does not
experimental data show a different behavior. The ratio always result in a higher gas production. The simulation
defined by Equation 16.5 can also be obtained from the studies (Agrawal and Sharma, 2013; Cheng, 2012) show that
experimental data using the slope of imbibition curves effective imbibition and extended shut‐in not only has negli-
presented in Figure 16.9. The ratio obtained from water and gible effects on long‐term well productivity but also can
oil imbibition experiments in horizontal (R ) and vertical improve early gas production. The water occupying the com-
H
(R ) shale packs are presented in Figure 16.12. Interestingly, plex fracture system can imbibe into the matrix and lead to
V
the values are consistently less than 1, which indicates that expelling of gas from matrix into the fractures during the
oil imbibes faster than water. This comparative analysis shut‐in period. The gas expelled from matrix accumulates in
indicates that the actual driving force imbibing the oleic the fracture network and can be produced with water during
phase into the crushed samples is stronger than the capillary the flowback operation (Adefidipe et al., 2014; Ghanbari
pressure modeled by Young–Laplace equation. Since the et al., 2013).
surface tension of water is higher than oil, this discrepancy Furthermore, the flowback water contains a significant
should be related to the strong affinity of the crushed amount of hardness, soil, heavy metals, chloride, salts,
shale particles to oil. In other words, the Young–Laplace organic elements, and also hydrocarbons and radionuclides
equation, even with the contact angle of zero (due to the from shale formations (Jiang, 2013). The recent strict envi-
complete spreading of oil on the shale surface), underesti- ronmental regulations prohibit flowback disposal especially
mates the strong suction or adsorption of oil by the crushed in the North America (Jiang, 2013). Another motive to man-
shale particles. age flowback water comes from the freshwater shortage in